[Federal Register Volume 80, Number 3 (Tuesday, January 6, 2015)]
[Proposed Rules]
[Pages 608-675]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2014-30033]
[[Page 607]]
Vol. 80
Tuesday,
No. 3
January 6, 2015
Part II
Department of the Interior
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Office of Natural Resources Revenue
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30 CFR Parts 1202 and 1206
Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation
Reform; Proposed Rule
Federal Register / Vol. 80 , No. 3 / Tuesday, January 6, 2015 /
Proposed Rules
[[Page 608]]
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DEPARTMENT OF THE INTERIOR
Office of Natural Resources Revenue
30 CFR Parts 1202 and 1206
[Docket No. ONRR-2012-0004]
RIN 1012-AA13
Consolidated Federal Oil & Gas and Federal & Indian Coal
Valuation Reform
AGENCY: Office of Natural Resources Revenue, Interior.
ACTION: Proposed rule.
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SUMMARY: The Office of Natural Resources Revenue (ONRR) proposes to
change the regulations governing valuation for royalty purposes of oil
and gas produced from Federal onshore and offshore leases and coal
produced from Federal and Indian leases. The proposed rule also
consolidates definitions for oil, gas, and coal product valuation into
one subpart applicable to the Federal oil and gas and Federal and
Indian coal subparts.
DATES: You must submit comments on or before March 9, 2015.
ADDRESSES: You may submit comments to ONRR on this proposed rulemaking
by any method below. Please refer to the Regulation Identifier Number
(RIN) 1012-AA13 in your comments. (See also Public Availability of
Comments under Procedural Matters.)
Electronically go to www.regulations.gov. In the entry
titled ``Enter Keyword or ID,'' enter ``ONRR-2012-0004,'' then click
``Search.'' Follow the instructions to submit public comments. ONRR
will post all comments.
Mail comments to Armand Southall, Regulatory Specialist,
P.O. Box 25165, MS 61030A, Denver, Colorado 80225.
Hand-carry comments, or use an overnight courier service,
to the Office of Natural Resources Revenue, Building 85, Room A-614,
Denver Federal Center, West 6th Ave. and Kipling St., Denver, Colorado
80225.
FOR FURTHER INFORMATION CONTACT: For comments or questions on
procedural issues, contact Armand Southall, ONRR, telephone (303) 231-
3221, or email at [email protected]. The authors of the proposed
rule are Sarah Inderbitzin, Richard Adamski, Michael DeBerard, Peter
Christnacht, Kimbra Davis, and Lance Wenger.
SUPPLEMENTARY INFORMATION:
I. Background
In 2007, the Royalty Policy Committee (RPC) Subcommittee on Royalty
Management issued a report titled ``Mineral Revenue Collection From
Federal and Indian Lands and the Outer Continental Shelf.'' The
Subcommittee's report recommended clarification of the regulations
governing onshore gas and transportation deductions to provide more
certainty for ONRR, BLM, and industry, which should result in better
compliance. More specifically, the Subcommittee recommended revisions
to the gas valuation regulations and guidelines to address the cost-
bundling issue and to facilitate the calculation of gas transportation
and gas processing deductions. The Subcommittee also recommended the
use of market indices for gas valuation in the context of non-arm's-
length transactions in lieu of benchmarks, which have been used since
1988.
The Subcommittee's report also recommended ``revis(ing) and
implement(ing) the regulations and guidance for calculating prices used
in checking royalty compliance for solid minerals, with particular
attention to non-arm's-length transactions.''
The current Federal oil valuation regulations have been in effect
since 2000, with a subsequent amendment relating primarily to the use
of index pricing in some circumstances. The current Federal gas
valuation regulations have been in effect since March 1, 1988, with
various subsequent amendments relating primarily to the transportation
allowance provisions. The current Federal and Indian coal valuation
regulations have been in effect since March 1, 1989, with minor
subsequent amendments relating primarily to the Federal black lung
excise taxes, abandoned mine lands fees, State and local severance
taxes, and washing and transportation allowance provisions. In the
years since we wrote these regulations, the Secretary of the Interior's
(Secretary) responsibility to determine the royalty value of minerals
produced has not changed, but the industry and marketplace have changed
dramatically. ONRR proposes these amendments to our valuation
regulations to permit the Secretary to discharge the Department of the
Interior's (Department) royalty valuation responsibility in an
environment of continuing and accelerating change in the industry and
the marketplace. The Secretary's responsibilities regarding oil and gas
production from Federal leases and coal production from Federal and
Indian leases require development of flexible valuation methodologies
that lessees can accurately comply with in a timely manner.
To increase the effectiveness and efficiency of our rules, ONRR is
proposing proactive and innovative changes. We intend for this proposed
rulemaking to provide regulations that (1) offer greater simplicity,
certainty, clarity, and consistency in product valuation for mineral
lessees and mineral revenue recipients; (2) are more understandable;
(3) decrease industry's cost of compliance and ONRR's cost to ensure
industry compliance; and (4) provide early certainty to industry and
ONRR that companies have paid every dollar due. Therefore, ONRR
proposes to amend the current regulations at 30 CFR part 1202, subpart
F, and part 1206, subparts C, D, F, and J, governing the valuation, for
royalty purposes, of oil, gas, and coal produced from Federal leases
and coal produced from Indian leases.
On May 27, 2011, ONRR published Advance Notices of Proposed
Rulemaking (ANPRs) regarding the valuation, for royalty purposes, of
oil, gas, and coal produced from Federal leases and coal produced from
Indian leases (76 FR 30878, 30881). ONRR received responses to the
Federal oil and gas valuation ANPR from 19 State, industry, industry
trade association, and the general public commenters. ONRR then
conducted 3 public workshops on Federal oil and gas valuation in
September and October 2011 in Houston, Texas, Washington, DC, and
Denver, Colorado. At the workshops, ONRR asked attendees to discuss,
among other things, the use of index prices to value oil and gas,
alternatives to the current requirement to track actual costs to
determine transportation allowances, and alternate methods for valuing
wellhead gas volumes to eliminate the requirement to trace the value of
liquids removed from processed gas.
ONRR received responses to the Federal and Indian coal valuation
ANPR from 11 industry representative, Tribe, State, community group
(representing several member groups), coal publication, and trade
organization commenters. ONRR then conducted 3 public workshops on
Federal and Indian coal valuation in October 2011 in Denver, Colorado;
St. Louis, Missouri; and Albuquerque, New Mexico. At those workshops,
ONRR asked attendees to discuss, among other things, (1) possible
alternatives to the current methods that we use to value arm's-length
and non-arm's-length coal sales, (2) coal comparability factors, (3)
possible alternatives to the current methods we use to value coal
cooperative sales of coal, (4) use of index prices to value coal, and
(5)
[[Page 609]]
possible alternatives to the current requirements to track actual costs
to determine transportation and washing allowances.
ONRR considered the input from the ANPRs and the workshops and
proposes this consolidated rulemaking to improve the current
regulations. The proposed rule would not alter the underlying
principles of the current regulations. By proposing these amendments,
the Department reaffirms that the value, for royalty purposes, of crude
oil and natural gas produced from Federal leases and coal produced from
Federal and Indian leases is determined at or near the lease and that
gross proceeds from arm's-length contracts are the best indication of
market value. Like the current regulations, these proposed regulations
would not restrict ONRR to a comparison of arm's-length sales of other
production occurring in the field or area to value production not sold
under an arm's-length contract. Thus, like the current regulations, in
this proposed rule, ONRR may begin with a ``downstream'' price or value
and determine value at the lease by allowing deductions for the cost of
transporting production to downstream sales points or markets, or by
allowing appropriate adjustments for location or quality.
Federal and Indian lessees are not obligated to sell their
production downstream of the lease. A lessee is at liberty to sell
production at or near the lease, even if selling downstream might yield
a higher royalty value than selling it at the lease. If a lessee
chooses to sell downstream, the choice to sell downstream does not make
otherwise non-deductible costs deductible (for example marketable
condition and marketing costs). See Independent Petroleum Ass'n of
America. v. DeWitt, 279 F.3d 1036 (D.C. Cir. 2002), cert. denied sub
nom., Independent Petroleum Ass'n of America. v. Watson, 537 U.S. 1105
(2003) (``Independent Petroleum Ass'n v. DeWitt''); Devon Energy Corp
v. Norton, No. 04-CV-0821 (GK), 2007 WL 2422005 (D.D.C. Aug. 23, 2007),
aff'd sub nom., Devon Energy Corp. v. Kempthorne, 551 F.3d 1030 (D.C.
Cir. 2008), cert. denied, 130 S. Ct. 86 (2009) (``Devon'') and cases
cited therein.
As noted above, the changes proposed in this rule reflect an effort
by ONRR to update its royalty valuation regulations to, among other
things, simplify processes and provide early clarity regarding
royalties owed. However, even with the changes outlined in this rule,
royalty valuations will continue to be complex, and the markets for
oil, gas, and coal will continue to evolve. Therefore, ONRR continues
to be interested in opportunities to further streamline the valuation
process, while also bringing added transparency to the system. In
particular, we seek ideas and comments on:
1. The potential for creating standardized ``schedules'' for
transportation and processing allowances to reduce the need to rely on
case-by-case operator reporting and agency review of actual costs.
2. Opportunities to more fundamentally reassess how non-arm's
length transactions are treated for the purposes of determining
royalties owed.
ONRR recognizes that the costs and benefits of making further
changes to its valuation regulations (beyond those specifically
proposed in this rule) will depend on the specific commodity at issue
(i.e., oil, gas or coal), as well as geographic or other factors. Thus,
detailed comments that elaborate on specific situations where further
valuation changes should be considered would be particularly useful to
ONRR as it proceeds with this rulemaking as well as any future rules
that may be considered.
II. Explanation of Proposed Amendments
Based on comments ONRR received on the ANPRs and at the public
workshops, and other relevant information, we propose this consolidated
rule to improve the current regulations to ensure greater clarity,
efficiency, certainty, and consistency in production valuation.
The general consensus of comments received on the ANPR about arm's-
length oil sales was that actual proceeds are the best indicator of
value, and ONRR should not change to index prices. Most commenters
agreed the valuation methodology for non-arm's-length sales of Federal
oil is working, as is using actual costs to determine transportation
allowances. Thus, ONRR is not currently proposing major changes to oil
valuation methodologies except to eliminate both unused valuation
options, such as tendering, and associated definition(s), and to make
the oil rule consistent with our proposed changes to the proposed
Federal gas rule.
The comments we received regarding gas produced from Federal leases
were, in certain instances, polarized. Very large companies generally
support index pricing as an option if it is revenue-neutral and there
are no required true-ups (end-of-year comparison of the index value to
actual sales and payment on the higher of the two). Independent gas
producers and States generally disagreed with the major companies and
did not support index pricing because they believe it may not reflect
actual value and may not be revenue neutral. The majority of
respondents generally support using actual costs for gas transportation
and processing deductions to maintain revenue neutrality. In response,
ONRR proposes no major changes for the valuation of arm's-length gas
sales. However, for non-arm's-length gas sales, ONRR proposes to
eliminate current benchmarks (a series of indicators of market value).
Instead, ONRR proposes valuation methodology options based on how gas
is sold using the first arm's-length-sale price (affiliate resales),
optional index prices, or weighted average pool prices.
The general consensus of ANPR commenters for coal valuation was not
to change royalty valuation of arm's-length sales and not to use coal
index values because of their very limited applicability. Commenters
suggested modifying the non-arm's-length coal benchmarks and
eliminating seldom-used benchmarks. Commenters agreed ONRR should keep
Federal and Indian rules separate. Therefore, at this time, ONRR is
proposing no changes to the valuation of arm's-length coal sales.
For non-arm's-length coal sales, ONRR proposes to eliminate the
current benchmarks. Instead, ONRR proposes to value coal on the gross
proceeds received from the first arm's-length sale. ONRR also proposes
to value sales of coal between coal cooperative members using the first
arm's-length sale or a netback methodology. In addition, if there is no
coal sale, and lessees or their affiliates use the coal to generate
electricity and sell the electricity, then ONRR proposes to value the
coal for royalty purposes based on the gross proceeds the lessee or its
affiliate receive for the power plant's arm's-length sales of the
electricity, less applicable deductions. ONRR proposes the same changes
for both Federal and Indian coal, with some minor exceptions, but would
continue to maintain separate regulations.
ONRR also proposes other changes to our regulations, although we
did not specifically request comments on these changes in the ANPRs or
at the workshops. One such proposed change is adding a new ``default
provision'' to address valuation when ONRR determines (1) a contract
does not reflect total consideration, (2) the gross proceeds accruing
to you or your affiliate under a contract do not reflect reasonable
consideration due to misconduct or breach of the duty to market for the
mutual benefit of the lessee and the lessor, or (3) it cannot
[[Page 610]]
ascertain the correct value of production because of a variety of
factors, including, but not limited to, a lessee's failure to provide
documents. In these cases, the Secretary may enforce his/her authority
and exercise considerable discretion to establish the reasonable value
of production using a variety of discretionary factors and any other
information the Secretary believes is appropriate.
Finally, we rewrote all sections of the current regulations in
Plain Language to meet the criteria of Executive Orders 12866 and 12988
and the Presidential Memorandum of June 1, 1998, and to make our rules
more clear, consistent, and readable. All citations to the current ONRR
regulations in title 30 of the Code of Federal Regulations (CFR) in
this preamble refer to the July 1, 2012, CFR.
III. Section-by-Section Analysis
Before reading the additional explanatory information below, please
turn to the proposed rule language that immediately follows the List of
Subjects in 30 CFR parts 1202 and 1206 and signature page in this
proposed rule. The Department will codify this language in the CFR if
we finalize the proposed rule as written.
After you read the proposed rule, please return to the preamble
discussion below. The preamble contains more information about the
proposed rule, such as why we define a term in a certain manner and why
we chose one valuation method over another.
The derivation table below only shows a crosswalk of the recodified
sections of the current and the proposed regulations in part 1206.
Derivation Table for Part 1206
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The requirements of section: Are derived from section:
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Subpart C
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1206.20...................... 1206.101; 1206.151; 1206.251; 1206.451.
1206.101..................... 1206.102.
1206.102..................... 1206.103.
1206.103..................... 1206.104.
1206.106..................... 1206.105.
1206.107..................... 1206.106.
1206.108..................... 1206.107.
1206.109..................... 1206.108.
1206.110..................... 1206.109.
1206.111..................... 1206.110.
1206.112..................... 1206.111.
1206.113..................... 1206.112.
1206.114..................... 1206.113.
1206.115..................... 1206.114.
1206.116..................... 1206.115.
1206.117..................... 1206.116.
1206.118..................... 1206.117.
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Subpart D
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1206.140..................... 1206.150.
1206.141(a)(1)-(4)........... 1206.152(a)(1).
1206.141(b)(1)-(3)........... 1206.152(a)(2).
1206.141(b)(4)............... 1206.152(b)(1)(iv).
1206.142(a)(4)............... 1206.153(a)(1).
1206.142(b).................. 1206.153(a)(2).
1206.142(c).................. 1206.153(b)(1)(i).
1206.143(a)(1) and (b)....... 1206.152(b)(1)(ii); 1206.153(b)(1)(ii).
1206.143(a)(2)............... 1206.152(f); 1206.153(f).
1206.143(c).................. 1206.152(b)(1)(iii); 1206.153(b)(1)(iii).
1206.144..................... 1206.152(c)(1)-(3); 1206.153(c)(1)-(3).
1206.145..................... 1206.152(e)(1) and (2); 1206.153(e)(1)
and (2); 1206.157(c)(1)(ii) and
(c)(2)(iii); 1206.159(c)(1)(ii) and
(c)(2)(iii).
1206.146..................... 1206.152(i); 1206.153(i).
1206.147..................... 1206.152(k); 1206.153(k).
1206.148..................... 1206.152(g); 1206.153(g).
1206.149..................... 1206.152(l); 1206.153(l).
1206.150..................... 1206.154.
1206.151..................... 1206.155.
1206.152(a).................. 1206.156(a).
1206.152(b).................. 1206.156(b); 1206.57(a)(2) and (b)(3).
1206.152(c)(1)............... 1206.157(a)(2) and (b)(4).
1206.152(f).................. 1206.157(a)(4).
1206.153(b).................. 1206.157(f).
1206.153(c).................. 1206.157(g).
1206.154(a).................. 1206.157(b).
1206.154(e)-(h).............. 1206.157(b)(2)(i)-(iii).
1206.154(i).................. 1206.157(b)(2)(iv).
1206.154(i)(3)............... 1206.157(b)(2)(v).
1206.155..................... 1206.157(c)(1)(i), (ii).
1206.156..................... 1206.157(c)(2)(i)-(iv).
1206.157(a)(1) and (c)....... 1206.156(d).
1206.157(a)(2) and 1206.158.. 1206.157(e).
[[Page 611]]
1206.159(a)(1)............... 1206.158(a).
1206.159(b).................. 1206.158(b).
1206.159(c)(1) and (2)....... 1206.158(c)(1) and (2).
1206.159(d).................. 1206.158(d)(1).
1206.160..................... 1206.159(a).
1206.161..................... 1206.159(b).
1206.162..................... 1206.159(c)(1).
1206.163..................... 1206.159(c)(2).
1206.164..................... 1206.159(d).
1206.165..................... 1206.159(e).
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Subpart F
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1206.250..................... 1206.250.
1206.251..................... 1206.254; 1206.255; 1206.260.
1206.252(d).................. 1206.258(a); 1206.261(b).
1206.260(a)(1) and (b)....... 1206.261(a).
1206.260(c)(2)............... 1206.261(a)(2).
1206.260(d).................. 1206.261(c)(3).
1206.260(e).................. 1206.261(c)(1), (c)(2), and (e).
1206.260(f).................. 1206.262(a)(4).
1206.260(g).................. 1206.262(a)(2) and (a)(3).
1206.261..................... 1206.262(a)(1).
1206.262..................... 1206.262(b).
1206.263..................... 1206.262(c)(1).
1206.264..................... 1206.262(c)(2).
1206.265..................... 1206.262(d).
1206.266..................... 1206.262(e).
1206.267(a).................. 1206.258(a).
1206.267(b)(2)............... 1206.258(c); 1206.260.
1206.267(c).................. 1206.259(a)(4).
1206.267(d).................. 1206.259(a)(2) and (a)(3).
1206.267(e).................. 1206.258(e).
1206.268..................... 1206.259(a)(1).
1206.269..................... 1206.259(b).
1206.270..................... 1206.259(c)(1).
1206.271..................... 1206.259(c)(2).
1206.272..................... 1206.259(d).
1206.273..................... 1206.259(e).
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Subpart J
------------------------------------------------------------------------
1206.450..................... 1206.450.
1206.451..................... 1206.453; 1206.454; 1206.459.
1206.460..................... 1206.461(a)(1).
1206.463..................... 1206.461(c).
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A. Section-By-Section Analysis of 30 CFR Part 1202--Royalties, Subpart
F--Coal
ONRR proposes to amend subpart F regarding Federal and Indian coal
production volumes on which you must pay royalties. The proposed rule
merely moves current 30 CFR 1206.253 and 1206.452 to 30 CFR part 1202,
subpart F to a new Sec. 1202.251. We also rewrote the current sections
in Plain Language without substantive change.
B. Section-By-Section Analysis of 30 CFR Part 1206--Product Valuation,
Subpart A--General Provisions and Definitions, Subpart C--Federal Oil,
Subpart D--Federal Gas, Subpart F--Federal Coal, and Subpart J--Indian
Coal
ONRR proposes to amend subparts A, C, D, F, and J relating to the
valuation of oil and gas produced from Federal leases and coal produced
from Federal and Indian leases.
Subpart A--General Provisions
1206.20 What definitions apply to subparts C, D, F, and J?
ONRR proposes to consolidate the definitions from Federal Oil (30
CFR 1206.101), Federal Gas (30 CFR 1206.151), Federal Coal (30 CFR
1206.251), and Indian Coal (30 CFR 1206.451). The consolidated
definitions reside in a proposed Sec. 1206.20 under proposed Subpart
A--General Provisions and Definitions.
ONRR proposes to consolidate the existing definitions for these
products to provide greater clarity and eliminate redundancy. Where
common terms exist in the four subparts, ONRR modifies the definitions
to incorporate the active voice and to use plain and simple language
similar to the language reflected in the 2000 Federal crude oil rule.
For example, the term arm's-length contract applies the modern language
of the 2000 Federal crude oil rule and extends its applicability to
Federal gas and Federal and Indian coal. Where a definition has
different meanings for different subparts, we define the term
[[Page 612]]
for each subpart in that definition. For example, see the definition of
``gross proceeds'' below. Terms we currently reference in only one
subpart, for example ANS (Alaska North Slope), remain unmodified,
except we propose to locate these definitions in the consolidated
definitions in Sec. 1206.20. Finally, ONRR proposes to add new
definitions.
We identify all new definitions in the table below and show if each
existing definition remains unchanged, is modified, or is eliminated.
Summary of Terms and Status
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Status
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Term Added new Removed
Modified Not modified definition definition
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Ad valorem lease............................ ............... X ............... ...............
Affiliate................................... X ............... ............... ...............
Allowance................................... ............... ............... ............... X
ANS......................................... ............... X ............... ...............
Area........................................ X ............... ............... ...............
Arm's-length contract....................... X ............... ............... ...............
Audit....................................... X ............... ............... ...............
BIA......................................... ............... X ............... ...............
BLM......................................... ............... X ............... ...............
BOEM........................................ ............... ............... X ...............
BSEE........................................ ............... ............... X ...............
Coal........................................ ............... X ............... ...............
Coal cooperative............................ ............... ............... X ...............
Coal washing................................ ............... X ............... ...............
Compression................................. ............... X ............... ...............
Condensate.................................. X ............... ............... ...............
Constraint.................................. ............... ............... X ...............
Contract.................................... X ............... ............... ...............
Designee.................................... ............... X ............... ...............
Exchange agreement.......................... ............... X ............... ...............
FERC........................................ ............... ............... X ...............
Field....................................... X ............... ............... ...............
Gas......................................... ............... X ............... ...............
Gas plant products.......................... ............... X ............... ...............
Gathering................................... X ............... ............... ...............
Geographic region........................... ............... ............... X ...............
Gross proceeds.............................. X ............... ............... ...............
Index....................................... X ............... ............... ...............
Index pricing point......................... X ............... ............... ...............
Index zone.................................. ............... ............... X ...............
Indian allottee............................. ............... ............... ............... X
Indian Tribe................................ X ............... ............... ...............
Individual Indian mineral owner............. ............... ............... X ...............
Keepwhole contract.......................... ............... ............... X ...............
Lease....................................... X ............... ............... ...............
Lease products.............................. X ............... ............... ...............
Lessee...................................... X ............... ............... ...............
Like quality................................ ............... ............... X ...............
Like quality coal........................... ............... ............... ............... X
Like-quality lease products................. ............... ............... ............... X
Location differential....................... ............... X ............... ...............
Market center............................... ............... X ............... ...............
Marketable condition........................ ............... X ............... ...............
Marketing affiliate......................... ............... ............... ............... X
Mine........................................ ............... X ............... ...............
Minimum royalty............................. ............... ............... ............... X
Misconduct.................................. ............... ............... X ...............
Net-Back method............................. ............... ............... ............... X
Net output.................................. X ............... ............... ...............
Net profit share............................ ............... ............... ............... X
Netting..................................... X ............... ............... ...............
NGLs........................................ ............... ............... X ...............
NYMEX price................................. ............... X ............... ...............
Oil......................................... ............... X ............... ...............
ONRR........................................ ............... X ............... ...............
ONRR-approved commercial price bulletin..... ............... ............... X ...............
ONRR-approved publication................... X ............... ............... ...............
Outer Continental Shelf..................... ............... X ............... ...............
Payor....................................... ............... ............... X ...............
Person...................................... X ............... ............... ...............
Posted price................................ ............... ............... ............... X
Processing.................................. X ............... ............... ...............
Processing allowance........................ ............... ............... X ...............
[[Page 613]]
Prompt month................................ ............... X ............... ...............
Quality differential........................ ............... X ............... ...............
Region...................................... ............... ............... X ...............
Residue gas................................. ............... X ............... ...............
Rocky Mountain Region....................... ............... X ............... ...............
Roll........................................ X ............... ............... ...............
Sale........................................ X ............... ............... ...............
Sales type code............................. ............... ............... ............... X
Section 6 lease............................. ............... X ............... ...............
Short ton................................... ............... ............... X ...............
Spot market price........................... ............... ............... ............... X
Spot price.................................. ............... X ............... ...............
Spot sales agreement........................ ............... ............... ............... X
Tendering program........................... ............... ............... ............... X
Tonnage..................................... ............... ............... X ...............
Trading month............................... ............... X ............... ...............
Transportation allowance.................... X ............... ............... ...............
Warranty contract........................... ............... ............... ............... X
Washing allowance........................... ............... ............... X ...............
WTI differential............................ ............... X ............... ...............
----------------------------------------------------------------------------------------------------------------
We explain the new and modified terms and definitions below. For
most modified terms, we rewrote the terms in Plain Language and make no
substantive change.
Subpart C--Federal Oil
1206.100 What is the purpose of this subpart?
This proposed section is the same as current 30 CFR 1206.100.
1206.101 How do I calculate royalty value for oil I or my affiliate
sell(s) under an arm's-length contract?
This proposed section is the same as current 30 CFR 1206.102 except
for two substantive changes. First, proposed paragraph (a) contains the
same provisions as existing Sec. 1206.102(a) with one modification.
Proposed paragraph (a) adds that the value in this paragraph does not
apply ``if ONRR decides to value your oil under Sec. 1206.105.''
Proposed Sec. 1206.105 is ONRR's new proposed default valuation
mechanism.
ONRR also proposes to add a new provision to paragraph (c)(1)
allowing ONRR to decide a lessee's oil value if the lessee fails to
make the election in this paragraph. Under the current regulations, if
a contract is either non-arm's-length or an exchange agreement, a
lessee can choose one of two different valuation methods. ONRR proposes
to add a new provision to clarify the current regulations by explaining
the consequences if a lessee fails to properly make the election. For
example, if a lessee improperly classifies its contract as an arm's-
length contract under the current regulations, the lessee will most
likely pay royalties on the price specified in its contract. However,
if the lessee or ONRR subsequently determines the contract actually was
non-arm's-length or an exchange agreement, the existing regulations do
not specify if the lessee may make the election retroactively. To
remove this ambiguity, ONRR proposes to eliminate the lessee's election
in these situations and provide that ONRR can determine the lessee's
oil value under the new default valuation mechanism in Sec. 1206.105.
1206.102 How do I value oil not sold under an arm's-length contract?
This proposed section is the same as current 30 CFR 1206.103 except
for two substantive changes. The first substantive change is to
paragraph (a), which explains when you may value oil under this
section. Proposed paragraph (a) requires you to use this section to
value your oil ``unless ONRR decides to value your oil under Sec.
1206.105.'' Proposed Sec. 1206.105 is ONRR's new proposed default
valuation mechanism.
ONRR also proposes to remove current 30 CFR 1206.103(b)(1)
containing the option for lessees to use a tendering program to value
oil they produce from Federal leases in the Rocky Mountain Region.
Since the final oil valuation regulations were published in March 2000,
ONRR is aware of only one company that valued its oil using this
provision. At that time, we received feedback from oil producers that
it was administratively inefficient to implement a tendering program
for valuation purposes. We do not believe any oil producer has used
this provision since then. Therefore, because industry has abandoned
its use of this provision, we propose to remove tendering from the
options available to value Federal oil produced in the Rocky Mountain
Region.
Finally, ONRR proposes to amend paragraphs (d) and (e) of Sec.
1206.103 in the current regulations. Under the current regulations,
lessees may apply paragraphs (d) and (e) to value their production with
ONRR approval. ONRR proposes to amend paragraphs (d) and (e) to instead
state that ONRR may decide to use these paragraphs to value production
under Sec. 1206.105.
1206.103 What publications are acceptable to ONRR?
The substantive requirements of this proposed section are the same
as current 30 CFR 1206.104. However, we propose to remove our
requirement to publish a notice of acceptable publications in the
Federal Register. Instead, we propose to provide acceptable
publications on our Web site.
1206.104 How will ONRR determine if my royalty payments are correct?
In this section, ONRR proposes amendments to the text of its gross
proceeds provisions to rewrite them in Plain Language and to make them
consistent with other valuation regulations. Thus, rather than repeat
the requirements or procedures in each applicable section of this rule,
ONRR proposes to have this section apply to this entire subpart.
However, the substantive requirements of proposed
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paragraphs (d), (e) and (f) remain unchanged. We propose the same
changes to the Federal gas amendments that we propose in this section,
so please refer to the discussion of the substantive changes we propose
to make to the Federal gas regulation in Sec. 1206.143 below for more
information.
1206.105 How will ONRR determine the value of my oil for royalty
purposes?
ONRR proposes to add a new ``default'' valuation Sec. 1206.105
under which ONRR can value your oil if we decide to do so pursuant to
the criteria under Sec. 1206.104 or any other provision in this
subpart. If ONRR determines value under this new default section, we
may consider any information we deem relevant. Also, this proposed
section enumerates factors ONRR may consider if we decide we will
determine value, for royalty purposes, under this section, which may
include, but not be limited to:
(a) The value of like-quality oil in the same field or nearby
fields or areas;
(b) The value of like-quality oil from the same plant;
(c) Public sources of price or market information ONRR deems
reliable;
(d) Information available and reported to ONRR, including but not
limited to, on Form ONRR-2014 and Form ONRR-4054;
(e) Costs of transportation or processing, if ONRR determines they
are applicable; or
(f) Any information ONRR deems relevant regarding the particular
lease operation or the salability of the oil.
This proposed section allows ONRR to consider any criteria we deem
relevant, as well as criteria similar to the current gas valuation
benchmarks under 30 CFR 1206.152(c)(1) and (2) and 1206.153(c)(1) and
(2). Like the valuation regulations in effect prior to the 1988
rulemaking that resulted in the current gas valuation regulations, 30
CFR 206.103 (1984) (onshore) and 206.150 (1984) (offshore), under
proposed Sec. 1206.105, ONRR has the authority and responsibility to
establish the reasonable value of production for royalty purposes and
possesses considerable discretion in determining that value.
Independent Petroleum Ass'n v. DeWitt, 279 F.3d at 1039-1040, and cases
cited therein. Thus, under this proposed section, ONRR has broad
authority to value your oil in the manner we deem most appropriate
considering the factors we deem most appropriate.
We add the same default provision to Federal gas in Sec. 1206.144,
Federal coal in Sec. 1206.254, and Indian coal in Sec. 1206.454.
1206.106 What records must I keep to support my calculations of value
under this subpart?
1206.107 What are my responsibilities to place production into
marketable condition and to market production?
The two proposed sections above are the same as current 30 CFR
1206.105 and 1206.106, except we rewrite the sections in Plain
Language.
1206.108 How do I request a value determination?
This proposed section is the same as current 30 CFR 1206.107 except
we make some substantive changes to provide greater clarity to the
process a lessee may use to request valuation guidance and
determinations, as well as the effect of ONRR's response to such
requests. Because we are making the same changes to the Federal gas
amendments in this proposed rulemaking, please refer to proposed Sec.
1206.148 of the Federal gas regulation below for more information.
1206.109 Does ONRR protect information I provide?
This proposed section is the same as current 30 CFR 1206.108,
except we rewrite the section in Plain Language.
1206.110 What general transportation allowance requirements apply to
me?
This proposed section is the same as current 30 CFR 1206.109 except
we reword the section name and make the following substantive changes.
First, in proposed paragraph (a)(2)(ii), we add a new provision that
states you may not take a transportation allowance for the movement of
oil produced on the OCS from the wellhead to the first platform.
Because we are making the same change to the Federal gas amendments we
propose in this rulemaking, please refer to Sec. 1206.152(a)(2)(ii) of
the Federal gas regulation below for more information.
Second, we propose in paragraph (b) to clarify that if you request
to use a different cost allocation than that in paragraph (b), and we
approve your request, you can only use your proposed allocation
methodology prospectively. We make this proposed change to clarify that
you may not request retroactive changes to your royalty reporting and
payment. We make the same change to proposed Sec. Sec. 1206.112(b),
1206.112(i)(1), 1206.112(j), 1206.113(c)(2), 1206.150(c)(4),
1206.152(b), 1206.154(b)(3), 1206.154(i)(1), 1206.161(b)(3),
1206.151(h)(1), 1206.262(b)(3), 1206.262(h)(1), 1206.269(b)(3),
1206.269(h)(1), 1206.462(b)(3), 1206.462(h)(1), 1206.463(d)(4)(i),
1206.469(b)(3), 1206.469(h)(1), and 1206.470(d)(4)(i).
Third, in paragraph (d)(1) of this section, we propose to remove
current 30 CFR 1206.109(c)(2) that allows a lessee to request to exceed
the limit on transportation allowances of 50 percent of the value of
the oil. We also propose to terminate existing approvals to exceed the
50 percent limit under paragraph (d)(2). Because we are making the same
change to the Federal gas amendments in this proposed rulemaking,
please refer to Sec. 1206.152(e) below for more information.
Fourth, like the default provision for valuation we discuss above
under Sec. 1206.104, proposed paragraph (f) provides that ONRR may
determine your transportation allowance under Sec. 1206.105 if (1)
there is misconduct by or between the contracting parties, (2) the
total consideration the lessee or its affiliate pays under an arm's-
length contract does not reflect the reasonable cost of transportation
because the lessee breached its duty to market oil for the mutual
benefit of the lessee and the lessor by transporting oil at a cost that
is unreasonably high, or (3) ONRR cannot determine if the lessee
properly calculated a transportation allowance for any reason. Because
we are making the same change to the Federal gas amendments we propose
in this rulemaking, please refer to the discussion of Sec. 1206.152(g)
below for more information on this provision.
Finally, we also propose a new provision under paragraph (g) to
clarify that you do not need ONRR's approval before reporting a
transportation allowance for costs you incur. This is consistent with
existing practice.
1206.111 How do I determine a transportation allowance if I have an
arm's-length transportation contract?
This proposed section is the same as current 30 CFR 1206.110,
except for three substantive changes. ONRR proposes to eliminate the
provision in current 30 CFR 1206.110(b)(4) that allows a lessee to
include the costs of carrying line fill on its books as a component of
arm's-length transportation allowances. Rather, we propose to
specifically preclude including this cost in transportation allowances
under new paragraph (c)(9) of this section. We propose to eliminate
allowing this cost because we believe this is a cost to market the oil
we disallow as a deduction under our existing valuation regulations.
Line fill occurs after the royalty measurement point and is necessary
for the pipeline operator to get Federal oil production to
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market. We request comments on whether this is a marketing cost.
We also propose to add a new paragraph (d) that applies if you have
no contract in writing for the arm's-length transportation of oil. In
that case, ONRR determines your transportation allowance under Sec.
1206.105. Under the proposed rule, you may propose to ONRR a method to
determine the allowance using the procedures in Sec. 1206.108(a) and
may use that method to determine your allowance until ONRR issues its
determination. This proposed paragraph does not apply if a lessee
performs its own transportation. Instead, proposed Sec. 1206.112 for
non-arm's-length transportation allowances, applies.
Finally, ONRR proposes to eliminate the provision in current 30 CFR
1206.110(g) that allows a lessee to report transportation costs, in
certain circumstances, as a transportation factor. We propose that a
lessee must report separately all transportation costs under both
arm's-length and non-arm's-length sales contracts as a transportation
allowance on Form ONRR-2014. ONRR believes requiring lessees to report
all deductions for transportation costs separately as allowances on
Form ONRR-2014 is more transparent, supports ONRR's increased data
mining efforts to promote accurate upfront royalty reporting, and
assists State and Federal auditors in their compliance work.
1206.112 How do I determine a transportation allowance if I do not have
an arm's-length transportation contract?
This proposed section is the same as current 30 CFR 1206.111 except
for the following substantive changes.
We replace current 30 CFR 1206.111(b)(3) and (b)(4) with proposed
paragraph (b)(3)(i) of this section, which allows you to elect to
calculate depreciation and a return on undepreciated capital investment
in a transportation system under proposed paragraph (b)(3)(i)(1) or a
return on undepreciated capital investment with no depreciation under
proposed paragraph (b)(3)(i)(2). The proposed regulation provides that
once you make an election, you may not change it without ONRR's
approval. In addition, proposed paragraph (b)(3)(ii) replaces current
30 CFR 1206.111(b)(5). Currently, 30 CFR 1206.111(b)(5) allows you to
continue deducting 10 percent of the cost of capital expenditures once
you have depreciated the asset below 10 percent under current 30 CFR
1206.111(j). However, under proposed paragraph (i)(1)(iii) of this
section, instead of allowing a 10 percent deduction, we base the return
on undepreciated capital investment on the reasonable salvage value of
the asset. ONRR believes this method more reasonably reflects the
actual costs for oil transportation systems. Also, it makes the
treatment of depreciation consistent with other royalty valuation
rules, including the current Federal gas rule at 30 CFR 1206.157(g)
(proposed Sec. 1206.154(i)).
In proposed paragraph (c)(2)(ii), we prohibit you from including
actual or theoretical line loss as a transportation cost. ONRR proposes
to eliminate the provision in the current regulations at 30 CFR
1206.111(b)(6)(v) which allows a lessee to reduce the royalty volume
measured at the royalty measurement point by actual or theoretical line
loss occurring after the royalty measurement point. This change is
consistent with long-standing mineral leasing laws that require royalty
on the volume of production removed from the lease. Mineral Leasing
Act, 30 U.S.C. 181-287; Mineral Leasing Act for Acquired Lands, 30
U.S.C. 351-359 (onshore acquired lands); Indian leasing statutes, 25
U.S.C. 396a--396g (tribal leases); 25 U.S.C. 396 (allotted leases); and
the Outer Continental Shelf Lands Act, 43 U.S.C. 1331-1356. This change
also makes Federal oil valuation consistent with ONRR's other product
valuation regulations.
Under proposed paragraph (c)(2)(iii), ONRR eliminates the provision
in current 30 CFR 1206.111(b)(6)(ii) which allows a lessee to include
the costs of carrying line fill on its books as a component of non-
arm's-length transportation allowances. We believe this is a cost to
market the oil, which we disallow as a deduction under current
valuation regulations. Line fill occurs after the royalty measurement
point and is necessary for the pipeline operator to get Federal oil
production to market. We request comments on whether this is a
marketing cost.
Proposed paragraph (i)(1) allows you to calculate depreciation and
a return on undepreciated capital investment using either a straight-
line method (based on either the life of the equipment or the life of
the reserves that the transportation system services) or a unit of
production method. This depreciation method was in ONRR's oil valuation
regulations in effect for producer-owned transportation systems prior
to the effective date of the 2000 Federal oil valuation regulations.
This new proposed paragraph (i)(1) would replace the provision in
current 30 CFR 1206.111(h), which allows a lessee to depreciate a
transportation asset a second time after the lessee already fully
depreciated that asset. The current Federal oil valuation regulations
authorize fully depreciated transportation assets to be recapitalized a
second time when they are purchased from the original owner. ONRR
proposes to remove this provision. Under proposed paragraph (i)(1)(ii),
ONRR allows depreciation of pipeline assets only one time. If the
pipeline asset is sold, we allow the purchaser to continue the
remaining allowance depreciation schedule if applicable. This change
makes Federal oil valuation consistent with ONRR's other product
valuation regulations.
Proposed paragraph (i)(1)(iii)(B) changes the return on
undepreciated capital investment from10 percent to the reasonable
salvage value of the asset multiplied by the rate of return in proposed
paragraph (i)(3) of this section.
New proposed paragraph (i)(2) provides an alternative to
depreciating the asset under paragraph (i)(1). Under this option, you
may elect to use a cost equal to the allowable initial capital
investment in the transportation system, multiplied by the rate of
return in proposed paragraph (i)(3) of this section. If you chose this
option, you may not include depreciation as a cost in your allowance.
ONRR removed the provision limiting this option to transportation
assets put in place after March 1, 1988. When ONRR published its
Federal oil valuation regulations on May 5, 2004, it changed the
requirements for transportation allowances. In recognition that certain
transportation facilities had been given approval prior to these
regulations' effective date (August 1, 2004), ONRR made the new
requirements apply only to facilities that were placed in service on or
after the effective date of these regulations. Now, almost ten years
later, ONRR believes that none of facilities affected by the 2004 rule
change are still eligible for depreciation under the requirements in
effect prior to August 1, 2004. Therefore, we remove this language from
the proposed regulations.
Proposed paragraph (i)(3) would amend current 30 CFR 1206.111(i)(2)
to change the Standard & Poor's BBB bond rate we allow as an
approximation of the cost of capital for non-arm's-length
transportation. Currently, 30 CFR 1206.111(i)(2) allows a lessee to
compute the rate of return on the undepreciated cost of capital by
multiplying the undepreciated amount remaining by 1.3 times the
Standard & Poor's BBB bond rate. ONRR proposes to decrease the
multiplier of the Standard & Poor's BBB bond rate from 1.3 to 1.0. In
the final Federal oil
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valuation regulations published in March 2000, we increased the
multiplier of the Standard & Poor's BBB bond rate from 1.0 to 1.3. We
propose to change it back to 1.0 times the BBB bond rate because we
believe this rate better reflects the cost of borrowing to finance
capital expenditures involved in pipeline construction. It also is
consistent with our other product valuation regulations.
When a company or affiliate invests in shipping its own production,
it considers if it can more profitably transport its own production or
contract with a third party to provide the service. At this stage in
production development, a company has a solid asset to demonstrate its
ability to repay the capital investment necessary to construct the
pipeline. ONRR consulted with FERC and has concluded that the BBB bond
rate is an adequate representation for the cost of capital for the
construction of producer-owned pipelines.
1206.113 What adjustments and transportation allowances apply when I
value oil production from my lease using NYMEX prices or ANS spot
prices?
1206.114 How will ONRR identify market centers?
1206.115 What are my reporting requirements under an arm's-length
transportation contract?
Proposed Sec. Sec. 1206.113 through 1206.115 are the same as
current 30 CFR 1206.112 through 1206.114, but we rewrite the sections
in Plain Language and update the examples in current 30 CFR 1206.112(d)
using November 2012 prices.
1206.116 What are my reporting requirements under a non-arm's-length
transportation contract?
This proposed section is the same as current 30 CFR 1206.115 except
we make each sentence a paragraph. We also add a new paragraph (d) that
explains you must follow the reporting requirements for arm's-length
contract under Sec. 1206.115 if you are authorized under Sec.
1206.112(j) to not use your actual costs.
1206.117 What interest and penalties apply if I improperly report a
transportation allowance?
This proposed section is the same as current 30 CFR 1206.116 except
we make each sentence a paragraph and add ``penalties'' to the heading
to better describe the section.
1206.118 What reporting adjustments must I make for transportation
allowances?
1206.119 How do I determine royalty quantity and quality?
These two proposed sections, 30 CFR 1206.118 and 1206.119, are the
same as current Sec. Sec. 1206.117 and 1206.119, respectively, but we
rewrite the sections in Plain Language.
1206.120 How are operating allowances determined?
We propose to remove current 30 CFR 1206.120 on how to determine
operating allowances because it is unnecessary. If a lease has
provisions for operating allowances, that lease term will govern
valuation under proposed Sec. 1206.100(d)(4) of this subpart.
Subpart D--Federal Gas
ONRR proposes to add new Sec. Sec. 1206.140 through 1206.149 to
this subpart to codify, clarify, and enhance current ONRR Federal gas
valuation practices.
1206.140 What is the purpose and scope of this subpart?
We propose to redesignate the current regulations at Sec. 1206.150
to Sec. 1206.160. Also, in this proposed rule, we rewrote the
redesignated sections in Plain Language. Proposed Sec. 1206.140 is the
same as current 30 CFR 1206.150 except for three changes. First, we
propose to add a new paragraph (b) to explain that the terms ``you''
and ``your'' in this subpart refer to the lessee. Second, we propose to
redesignate paragraphs (b) and (c) as paragraphs (c) and (d). Finally,
we propose to remove existing regulations in paragraph (d), which state
this subpart is intended to ensure leases are administered in
accordance with governing mineral leasing laws and lease terms. We
believe current paragraph (d) is unnecessary and duplicative of our
authority to promulgate this rule.
1206.141 How do I calculate royalty value for unprocessed gas I or my
affiliate sell(s) under an arm's-length or non-arm's-length contract?
This proposed section explains the valuation of unprocessed gas for
royalty purposes. Proposed paragraph (a)(1) explains that this section
applies to unprocessed gas--meaning gas that is never processed--
consistent with the current gas regulations.
Proposed paragraph (a)(2) explains this section applies to gas you
are not required to value under proposed Sec. 1206.142, or that ONRR
does not value under proposed Sec. 1206.144. Proposed Sec.
1206.142(a) explains what gas ONRR considers processed for valuation
purposes, and proposed Sec. 1206.144 explains ONRR's new proposed
default valuation mechanism. We discuss proposed Sec. Sec. 1206.142
and 1206.144 below.
Under proposed paragraph (a)(3), we state this section also applies
to processed gas you must value prior to processing under Sec.
1206.151 of this part. Proposed Sec. 1206.151 contains the dual
accounting provisions for Federal gas in current 30 CFR 1206.155.
Under proposed paragraph (a)(4), we consider unprocessed gas any
gas you sell prior to processing if price is based on an amount per
MMBtu or Mcf, and not on the value of residue gas and gas plant
products. Therefore, this proposed paragraph applies to the valuation
of gas when price is not based on a processed gas price.
Paragraph (b) proposes a new valuation methodology based on the
first arm's-length sale of the gas. ONRR promulgated the current gas
valuation regulations in 1988 to achieve market value based on
transactions between independent, non-affiliated parties. The
Department has long believed the values established in arm's-length
transactions are the best indication of market value, and the 1988
rules reflect that belief.
Although the Secretary's responsibility to determine the royalty
value of minerals produced has not changed, the industry and
marketplace have changed dramatically since we wrote the 1988
regulations. As discussed below, industry and marketplace changes, as
well as litigation necessitate changes to ONRR's valuation regulations.
Indeed, ONRR already amended the Indian gas (30 CFR part 1206, subpart
E) and Federal oil (30 CFR part 1206, subpart C) valuation regulations
to simplify those regulations and provide early certainty by valuing
those products based on the first arm's-length sale and/or on publicly
available prices.
When we developed the 1988 rules, producers most commonly sold
natural gas at the wellhead to natural gas pipeline companies, which
transported and sold the gas to local distribution companies. However,
from mid-1980 to early 1990, a series of FERC rulemakings resulted in
deregulation of some pipeline systems. As a result, industry now sells
directly to end users or distributors, and pipelines only provide
transportation services. Producers also created marketing affiliates to
which they initially transferred production.
For lessee sales to affiliates, the current Federal gas valuation
regulations require a lessee to value
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production based on a series of ``benchmarks'' to be applied in a
prescribed order (30 CFR 1206.152(c)). The first benchmark is the gross
proceeds accruing to the lessee in a sale under its non-arm's-length
contract, provided that those gross proceeds are equivalent to the
gross proceeds derived from, or paid under, comparable arm's-length
contracts (30 CFR 1206.152(c)(1)). This method has posed practical
difficulties since companies are not privy to other companies'
``comparable'' sales transactions. In addition, ONRR and lessees have
found it difficult to determine what portion of lease production a
lessee must sell at arm's-length to reliably determine the value of the
remaining production. Likewise, the remaining benchmarks at 30 CFR
1206.152(c)(2) and (3) have proven difficult for industry to follow and
ONRR to administer. ONRR proposes to replace the current regulations in
Sec. 1206.152(c)(1), (2), and (3) with proposed paragraph (b).
To simplify and clarify valuation of non-arm's-length sales,
proposed paragraph (b) bases value on the first arm's-length sale with
applicable allowances. The first arm's-length sale may occur
immediately, or may follow one or more non-arm's-length transfers or
sales of the gas. However, under the proposed rule, you will use the
first arm's-length sale regardless of whether you sell or transfer gas
to one or more affiliates or other persons in non-arm's-length
transactions before the first arm's-length sale, and regardless of the
number of those non-arm's-length transactions. This arm's-length sales
value will apply unless you exercise the index-based option in proposed
paragraph (c) of this section we discuss below.
Proposed paragraph (b)(1) would state value is the gross proceeds
accruing to you under an arm's-length contract, less applicable
allowances.
Similarly, under proposed paragraph (b)(2), if you sell or transfer
your Federal gas production to your affiliate, or some other person at
less than arm's length, and that person or its affiliate then sells the
gas at arm's length, royalty value will be the other person's (or its
affiliate's) gross proceeds under the first arm's-length contract. For
example, a lessee might sell its Federal gas production to a person who
is not an ``affiliate'' as defined, but with whom its relationship is
not one of ``opposing economic interests'' and therefore is not at
arm's length. An illustrative example is when a number of working
interest owners in a large field form a cooperative venture that
purchases all of the working interest owners' production and resells
the combined volumes to a purchaser at arm's-length. Xeno, Inc., 134
IBLA 172 (1995), involved a similar situation. If none of the working
interest owners own 10 percent or more of the new entity, the new
entity would not be an ``affiliate'' of any of them. Nevertheless, the
relationship between the new entity and the respective working interest
owners is not at arm's length because of the lack of opposing economic
interests regarding the contract. In this case, we believe it
appropriate to value the production based on the arm's-length sale
price the cooperative venture receives for the gas. Therefore, under
proposed paragraph (b)(2), you must value the production based on the
gross proceeds accruing to you, your affiliate, or other person to whom
you transferred the gas (or its affiliate) when the gas ultimately is
sold at arm's length, unless you elect to use the index pricing option
we propose under Sec. 1206.141(c) of this section or ONRR decides to
value your gas under the new default valuation provision in proposed
Sec. 1206.144 discussed below.
In summary, to provide early certainty and simplification, ONRR
proposes to amend its valuation regulations for Federal gas to provide
that, with certain exceptions, the first arm's-length sale is the value
for royalty purposes consistent with valuation of non-arm's-length
sales of Federal oil production under current 30 CFR 1206.102(a).
Proposed paragraph (b)(3) explains valuation if you, your
affiliate, or another person sell under multiple arm's-length contracts
for gas produced from a lease that is valued under this proposed
paragraph (b). In this case, unless you exercise the index-based option
we provide in paragraph (c) of this section, because you sold non-arm's
length to your affiliate or another person, under the proposed rule,
you must value the gas based on the volume-weighted average of the
value established under this paragraph for each contract for the sale
of gas produced from that lease. This is identical to current 30 CFR
1206.102(b) applicable to valuation of Federal oil. In addition, we
believe this provision is consistent with ongoing practice under the
current gas valuation rule.
Proposed paragraph (b)(4) contains the provisions of the current
gas valuation rule at 30 CFR 1206.152(b)(1)(iv) that explains how to
value over-delivered volumes under a cash-out program, but we rewrite
this provision in Plain Language.
ONRR proposes to add a new paragraph (c) containing an index price
valuation methodology that a lessee may elect to use in lieu of valuing
its gas under proposed paragraphs (b)(2) and (b)(3) of this section
based on the gross proceeds accruing to its affiliate or other person
under the first arm's-length sale. The proposed methodology is based on
publicly available index prices less a specified deduction to account
for processing and transportation costs. Under the proposed rule, this
valuation methodology also applies to ``no contract'' situations we
describe below under paragraph (e).
We believe this index price option simplifies the current valuation
methodology and provides early certainty. Many pipelines and service
providers now charge producers ``bundled'' fees that include both
deductible costs of transportation and non-deductible costs to place
production into marketable condition. Both ONRR and lessees with arm's-
length transportation contracts have found allocating the costs between
placing the gas in marketable condition and transportation is
administratively burdensome and time consuming. Similarly, when
processing plants charge bundled fees that include non-deductible
costs, the cost allocation is administratively burdensome and time
consuming.
Litigation also has complicated the application of ONRR's gas
valuation regulations. Although litigation has clarified what
constitutes marketable condition, its application is fact specific and
time consuming. See Devon and cases cited therein.
The proposed index-based option provides a lessee with an
alternative that is simple, certain, and avoids the requirements to
``trace'' production when there are numerous non-arm's-length sales
prior to an arm's-length sale and unbundle fees. Under this proposed
paragraph (c), the lessee may choose to value its gas only in an area
that has an active index pricing point published in a publication that
ONRR approves. The lessee may elect to value its gas under this
proposed paragraph, and that election is binding on the lessee for 2
years. ONRR would post a list of approved publications at www.onrr.gov.
ONRR proposes to use Platts and Natural Gas Intelligence as ONRR-
approved publications but invites comments on whether these
publications are appropriate, as well as whether there are other
publications that ONRR should use.
If the lease is in an area with active index pricing points, the
lessee must determine the applicable index pricing point or points. We
used the language in proposed paragraphs (c)(1)(i) and (ii) ``If you
can only transport to one index pricing point'' and ``If you can
transport
[[Page 618]]
gas to more than one index pricing point,'' respectively (emphasis
added), because, under the proposed rule, we intend that for an index
pricing point to be applicable, the lessee must be able to physically
transport its gas by pipeline to that index pricing point. Further, an
index pricing point would be applicable as long as the lessee could
physically transport their gas by pipeline to that index pricing point
(emphasis added). This means that under the proposed rule, the index
pricing point applies even if the lessee could not transport its gas to
that index pricing point because the pipeline is constrained (for
example when all available capacity on a pipeline through which the
lessee's gas might flow to that index pricing point was already under
contract to other parties).
For example, assume you have a lease in the West Delta area of the
Gulf of Mexico and your lease is physically connected by pipeline to
the Mississippi Canyon Pipeline. In this case, your gas is physically
capable of flowing to the Toca Plant (through the Southern Natural Gas
Pipeline), the Yscloskey Plant (through the Tennessee Gas Pipeline), or
the Venice Plant, and you have multiple index pricing points to which
your gas can physically flow. Also, assume the highest reported monthly
bid week price among the multiple index pricing points is the Tennessee
Gas 500 Leg Price at the tailgate of the Yscloskey Plant. Finally,
assume you cannot flow your gas through the Tennessee Gas Pipeline (to
the Yscloskey Plant) because all available capacity on that pipeline is
under contract to other persons, and the pipeline has no capacity
available to you for the production month--in other words, it is
constrained. In this example, you would use the highest reported
monthly bid week price at the tailgate of the Yscloskey Plant as the
value under this paragraph even though your gas did not flow to that
index pricing point during the production month.
Under proposed paragraph (c), the lessee could not use index
pricing points if it could not physically transport its gas to that
index pricing point because there is not a pipeline or series of
pipelines that physically connect to the lease and flow from the lease
to the index pricing point. ONRR would exclude the use of these index
pricing points because they do not represent points at which the lessee
can sell its gas, and it is difficult to adjust these prices for
location differentials between the index pricing points and the lease.
If the lessee can transport its gas to only one index pricing
point, the value under proposed paragraph (c)(1)(i) is the highest
reported monthly bid week price for that index pricing point in the
ONRR-approved publication for the production month. If the lessee can
transport its gas to more than one index pricing point, the value under
proposed paragraph (c)(1)(ii) is the highest reported monthly bid week
price for the index pricing points to which the lessee could transport
its gas, in the ONRR-approved publication for the production month.
However, under paragraph (c)(1)(iii), if there are sequential index
pricing points on a pipeline, the lessee would use the first index
pricing point at or after the lessee's gas enters the pipeline.
ONRR recognizes that index pricing points are normally located off
the lease, and frequently at lengthy distances from the lease. Thus,
under proposed paragraph (c)(1)(iv), ONRR allows a lessee to reduce the
highest reported monthly bid week price by a set amount to account for
transportation costs a lessee would incur to move the gas from the
lease to an applicable index pricing point. ONRR proposes to allow a
lessee to reduce the highest reported monthly bid week prices by 5
percent for sales from the OCS Gulf of Mexico and by 10 percent for
sales from all other areas, but not by less than 10 cents per MMBtu or
more than 30 cents per MMBtu. ONRR proposes these percent reductions
based on the average gas transportation rates that lessees have
reported to ONRR from 2007 through 2010 for OCS and all other areas.
ONRR proposes to allow a lessee to choose the index price
methodology to value its gas under this paragraph for the following
reasons: (1) It relies on a market price at which gas is sold from the
area during the production month; (2) it recognizes costs that a lessee
must incur to transport gas from the lease to an index pricing point;
and (3) it makes payment and verification of royalties paid simple and
efficient, thereby saving both lessees and ONRR significant
administrative costs. Further, ONRR believes this alternative
methodology provides ONRR with a reasonable market value for the
lessee's gas that avoids requiring a lessee and ONRR to track every
resale of the lessee's gas during the production month, especially when
those sales can involve several transactions hundreds of miles
downstream from the lease. As we state above, it also avoids the
unbundling of transportation and processing costs.
ONRR proposes to use the highest reported monthly bid week price
with a reduction for transportation costs. We propose this because it
generally represents the gross proceeds net of transportation
allowances accruing to lessees that ONRR believes are most likely to
choose this option to value their gas based on information lessees and
others reported on Form ONRR-2014 for the period from 2007 through
2011.
Proposed paragraph (c)(1)(v) states that, after you select an ONRR-
approved publication available at www.onrr.gov, you may not select a
different publication more often than once every 2 years. ONRR also
proposes, under paragraph (c)(1)(vi), to exclude individual index
prices from this option if we determine that the index price does not
accurately reflect the value of production. ONRR plans to disallow the
use of index prices with low liquidity, such as those classified as
Tier 3 in the Platts publications. ONRR would post a list of excluded
index pricing points at www.onrr.gov. We would appreciate comments on
this proposal.
Proposed paragraph (c)(2) explains that you may not take any other
deductions from the value calculated under this paragraph (c) because
you would already receive a reduction for transportation under proposed
paragraph (c)(1)(iv).
Proposed paragraph (d)(1) provides that, if you have no written
contract or no sale of gas subject to this section and there is an
index pricing point for the gas, then you must value your gas under the
index pricing provisions of paragraph (c) of this section unless ONRR
values your gas under Sec. 1206.144. This provision includes, but is
not limited to, when: (1) The lessee sells its gas to an affiliate and
the affiliate uses the gas in its facility; (2) the lessee sells its
gas to an affiliate and the affiliate resells the gas to another
affiliate of either the lessee or itself and that affiliate uses the
gas in its facility; (3) the lessee uses the gas as fuel for its other
leases in the field or area; or (4) the lessee delivers gas to another
person as payment of an overriding royalty interest that other person
holds.
Proposed paragraph (d)(2) addresses situations in which you have no
contract for the sale of gas subject to this section and there is not
an index pricing point for the gas. In these situations, ONRR will
decide the value under Sec. 1206.144. However, when this occurs, under
paragraph (d)(2)(i), we require that you propose to ONRR a method to
determine the value using the procedures in proposed Sec. 1206.148(a).
Proposed Sec. 1206.148(a) describes the information you must provide
to ONRR when you request a valuation
[[Page 619]]
determination. Proposed paragraph (d)(2)(ii) allows you to use your
proposed method until ONRR issues a decision. After ONRR issues a
determination, under paragraph (d)(2)(iii), you will have to make any
adjustment under proposed Sec. 1206.143(a)(2). You have to make
adjustments only if ONRR decides you must use a different methodology
than you propose under paragraph (d)(2)(i).
1206.142 How do I calculate royalty value for processed gas I or my
affiliate sell(s) under an arm's-length or non-arm's-length contract?
ONRR proposes a new Sec. 1206.142 including a new paragraph (a)
that amends and expands what is processed gas for royalty valuation
purposes. Currently, when gas is sold under an arm's-length contract
prior to processing, and the lessee neither retains nor exercises any
rights to the gas after processing (in other words, an outright sale
before the plant), such gas is valued as unprocessed gas. Included are
contracts where the title passes before processing, but payment is
based on the values of residue gas and gas plant products after
processing. Percentage-of-Proceeds (POP) contracts (contracts where the
lessee's arm's-length contract for the sale of that gas prior to
processing provides for the value to be determined on the basis of a
percentage of the purchaser's proceeds resulting from processing the
gas) are the most common of these contracts, but ONRR has observed a
myriad of variations of such contracts. Because this gas is valued as
unprocessed gas under the current regulations, there are no limits on
the minimum value of such gas for royalty purposes, except for gas sold
under arm's-length POP contracts, which has a minimum value of 100
percent of the residue gas. No such limitation applies to contracts
that do not specifically qualify as POP contracts.
For example, if the sales value is based on a percentage of an
index price for residue gas and/or NGLs, the current regulations base
value simply on the gross proceeds the lessee receives under the
contract. In essence, the unprocessed gas regulations allow such sales
arrangements to reduce the value of residue gas below the 100-percent
minimum value required under the processed gas regulations and below
the 1-percent minimum value for NGLs (assuming ONRR approves an
exception under the current rules in excess of 66\2/3\ percent of the
NGL value) required for processed gas.
ONRR has seen numerous contract arrangements that provide payment
terms based on: (1) A percentage of the volume or value of residue gas,
plant products, or any combination of the two actually recovered at the
plant; (2) the full volume and value of residue gas and/or plant
products recovered at the plant, less a flat fee per MMBtu of wet gas
entering the plant; (3) a combination of (1) and (2); and (4) the value
of a percentage of the theoretical volumes of residue gas and/or plant
products contained in the wet gas stream (so-called casing head gas
contracts). Because the many contract variations base the underlying
value on processed gas values, ONRR believes we should require a lessee
to value gas sold under such contracts as processed gas for royalty
purposes. This proposal provides the protection the current processed
gas regulations have against excessive transportation and processing
allowances and prevents a lessee from structuring contracts to avoid
these requirements. Such a change also clarifies if gas is processed
gas or unprocessed gas.
In summary, under proposed paragraph (a)(1), ONRR will consider gas
you or your affiliate do not sell or otherwise dispose of under an
arm's-length contract before processing ``processed gas.'' Paragraph
(a)(1) also applies to non-arm's-length sales of gas before processing
and transfers to a plant without a contract like the current
regulations.
Proposed paragraph (a)(2) applies to the situations described above
when payment is based on any constituent products resulting from
processing, such as residue gas, NGLs, sulfur, or carbon dioxide. We
would value POP contracts, percentage-of-index contracts, casing head
gas contracts, and contracts with any such variations of payment based
on volumes or value of those products as processed gas. With the
exception of POP contracts, this constitutes a departure from current
practice.
Proposed paragraph (a)(3), while not a change in current regulatory
practice, explicitly states that the lessee must value gas processed
under a keepwhole contract as processed gas. Under proposed Sec.
1206.20, we define a keepwhole contract as a processing agreement under
which the processor compensates the lessee by delivering to the lessee
a quantity of residue gas after processing equivalent to the quantity
of gas the processor received prior to processing, normally based on
heat content, less gas used as plant fuel and gas that is unaccounted
for and/or lost. The lessee does not receive NGLs under these
contracts. Over the past several years, ONRR has witnessed much
confusion over how to value gas sold under such contracts for royalty
purposes. This provision makes it clear that the lessee must value gas
processed under a keepwhole contract as processed gas. That is, royalty
would be based on 100 percent of the value of residue gas, 100 percent
of the value of gas plant products, plus the value of any condensate
recovered downstream of the point of royalty settlement prior to
processing, less applicable transportation and processing allowances.
To illustrate how to calculate the processing allowance in these
cases, assume you deliver 32,000 MMBtu of natural gas to the gas
processing plant. Also assume 7,000 MMBtu represents the shrinkage
volume (the MMBtu equivalent of the NGLs recovered), and the plant
recovers and retains 92,000 gallons of NGLs from your gas. Further,
assume the plant returns 7,000 MMBtu of gas to you at the tailgate of
the plant in addition to the residue gas that results after processing
your gas to ``keep you whole.'' Finally, assume the 7,000 MMBtu of gas
returned to you is worth $42,000 and the NGLs the plant retained are
worth $63,000. In this example, the cost you incur to process the gas
is $21,000 ($63,000-$42,000). If you incur additional costs, for
example a $0.03 per MMBtu fee times the 32,000 MMBtu you deliver to the
plant for processing, then you add those additional costs (in this
example, $960) to the $21,000 cost calculated above to determine your
total processing costs (in this example $21,960).
Proposed paragraph (a)(4) simply restates current 30 CFR
1206.153(a)(1) regarding arm's-length contracts and reservations of
rights to process gas the lessee or its affiliate exercises.
ONRR also proposes paragraph (b), which contains the same
requirements as current 30 CFR 1206.153(a)(2), but we rewrite it in
Plain Language, without substantive change.
Like the valuation of unprocessed gas under proposed Sec.
1206.141(b), proposed paragraph (c) provides that the value of residue
gas or any gas plant product under this section is the gross proceeds
accruing to you or your affiliate under the first arm's-length
contract. Also, like proposed Sec. 1206.141(b), this value does not
apply if you exercise the index-based option we provide in paragraph
(d) of this section or if ONRR decides to value your residue gas or any
gas plant product under the new default valuation provision in Sec.
1206.144. Proposed paragraphs (c)(1), (2), (3), and (4) explain to
which transactions this paragraph applies. See the discussion of
[[Page 620]]
the identical proposal for proposed Sec. Sec. 1206.141(b)(1), (2),
(3), and (4) above.
Proposed paragraph (d) contains the index-based valuation option
for valuation of your residue gas and NGLs. Under this proposed rule,
you may elect to value either your residue gas or your NGLs under the
index-based option, or you may elect to value both of them under this
option if your residue gas or NGLs meet the requirements for using the
optional valuation methodology we discuss above. Like the current
Federal oil regulations (30 CFR 1206.102(d)(1)(ii)) and proposed Sec.
1206.141(c), you cannot change your election to use this paragraph (d)
to value your gas more often than once every two years.
Proposed paragraph (d)(1) applies to residue gas. It has the same
index price option as proposed Sec. Sec. 1206.141(c)(i) through (vi)
we discuss above using index pricing points.
Proposed paragraph (d)(2) contains the index-based pricing option
for NGLs. Under paragraph (d)(2)(i), if you sell NGLs in an area with
one or more ONRR-approved commercial price bulletins available at
www.onrr.gov, you may choose one bulletin, and your value for royalty
purposes would be the monthly average price for that bulletin for the
production month. We consider you to be selling NGLs in an area with an
ONRR-approved commercial price bulletin if actual sales of NGLs that
the plant processing your gas recovers are made using NGLs prices in an
ONRR-approved commercial price bulletin. For example, in ONRR's
experience, actual sales of NGLs recovered in plants in New Mexico
commonly reference Mt. Belvieu prices in Platts, while actual sales of
NGLs recovered in plants in certain parts of Wyoming reference Mt.
Belvieu or Conway, Kansas prices. If your gas is processed at one of
these plants with these types of actual sales arrangements, under this
proposed rule, ONRR will consider you to be selling NGLs in an area
with an ONRR-approved commercial price bulletin. In that case, you may
elect to value your NGLs using the index price method if your NGLs meet
the requirements for using that method. ONRR will monitor actual sales
of NGLs and eliminate any area where an active market using NGLs prices
in an ONRR-approved commercial price bulletin ceases to exist.
Under proposed paragraph (d)(2)(ii), you may reduce the index-based
value you calculate under paragraph (d)(2)(i) by a specified amount to
account for a theoretical processing allowance and transportation and
fractionation (T&F). Therefore, the reduction includes two components
we calculated--an allowance based on processing allowance information
lessees report to ONRR and T&F based on our review of gas plant
contracts and gas plant statements.
For the processing allowance component, ONRR examined processing
allowances that lessees and others reported from January 2007 through
October 2011. We segregated the data into 2 subsets--the first being
the Gulf of Mexico (GOM) and the second being onshore Federal leases
and OCS leases other than those in the GOM. We segregated the leases
geographically because the GOM is closer to major market centers at Mt.
Belvieu, Napoleonville, and Geismer/Sorrento and, generally, has its
own processing, transportation, and fractionation regimen that is
distinct from the rest of the country. We do not believe it is fair or
accurate to benchmark processing for the entire country based on the
economics of GOM processing.
We could not segregate non-arm's-length processing allowances
because lessees do not identify processing allowances as arm's-length
or non-arm's-length when they report to ONRR. Rather, we calculated a
weighted average cents per gallon processing allowance by month for
both GOM and all other Federal leases. Using the weighted average cents
per gallon processing allowance we calculated, we determined the
average allowance rate over the 5-year period, along with the maximum
and minimum monthly rates as follows:
------------------------------------------------------------------------
GOM Other
------------------------------------------------------------------------
Average Rate.................... 17 [cent]/gal..... 22 [cent]/gal.
Maximum Rate.................... 29 [cent]/gal..... 32 [cent]/gal.
Minimum Rate.................... 10 [cent]/gal..... 15 [cent]/gal.
------------------------------------------------------------------------
Because we intend for this option to provide a simple method for
ONRR to calculate and provide to lessees, we used the minimum, rather
than the average rate, for the processing allowance portion of the
deduction. For both the GOM and all other Federal leases, the minimum
rate is 7 cents less than the average rate. ONRR believes that: (1) The
minimum allowance best protects the public interest and (2) a lessee
experiencing higher costs than this rate does not have to elect to use
this option and the lower cost allowance. Moreover, ONRR believes that
7 cents is a reasonable tradeoff given the simplicity, certainty, and
commensurate administrative savings this option would provide a lessee.
For the T&F part of the reduction, ONRR examined contracts that
specified T&F. If contracts did not specify T&F, we looked at the gas
plant statements. If the statements listed T&F as a line item, we used
that line item as the T&F. If the statements did not list T&F as a line
item, we calculated the difference between the price on the plant
statement and an appropriate published price to approximate the T&F. We
then averaged these T&F costs for GOM, New Mexico, and other as
follows:
----------------------------------------------------------------------------------------------------------------
GOM New Mexico Other
----------------------------------------------------------------------------------------------------------------
Average T&F.......................... 5 [cent]/gal........... 7 [cent]/gal........... 12 [cent]/gal.
----------------------------------------------------------------------------------------------------------------
We broke out New Mexico because the T&F fees for New Mexico plants
were consistently around 7 cents per gallon and were considerably less
than for other onshore plants. We then added the processing allowances
we calculated and the T&F. Based on the 5-years' worth of data
discussed above, we calculated the total NGLs reductions lessees could
use under this option are as follows:
[[Page 621]]
----------------------------------------------------------------------------------------------------------------
GOM New Mexico Other
----------------------------------------------------------------------------------------------------------------
NGLs Deduction....................... 15 [cent]/gal.......... 22 [cent]/gal.......... 27 [cent]/gal.
----------------------------------------------------------------------------------------------------------------
Under paragraph (d)(2)(ii), rather than publish the reductions in
the CFR, ONRR proposes to post the reductions at www.onrr.gov for the
geographic location of your lease. ONRR proposes to calculate the
reductions using the methodology explained above. This process would
give ONRR the flexibility to quickly recalculate and provide revised
reductions to lessees in response to market changes. This methodology
would be binding on you and ONRR. Under paragraph (d)(4), ONRR would
update the allowable reductions periodically using this methodology and
post changes at www.onrr.gov.
Proposed paragraph (d)(2)(iii) explains that after you select an
ONRR-approved commercial price bulletin available at www.onrr.gov, you
may not select a different commercial price bulletin more often than
once every two years. Under proposed paragraph (d)(3), you may not take
any other deductions from the value you used under this paragraph (d)
because it already includes reductions for transportation and
processing.
Proposed paragraph (e) mirrors proposed Sec. 1206.141(d). It
explains how you must value your processed gas if you have no written
contract for the sale of gas or no sale of the gas subject to this
section.
1206.143 How will ONRR determine if my royalty payments are correct?
In this section, ONRR proposes amendments to the current gross
proceeds provisions, rewriting them in Plain Language and making them
consistent with our other product valuation regulations (such as
geothermal resources and Federal oil). Like those published
regulations, rather than repeating the requirements or procedures in
each applicable section of this proposed rule, ONRR proposes to apply
this section to this entire subpart. However, the substantive
requirements of proposed paragraphs (d), (e), and (f) remain unchanged.
Below we discuss the paragraphs with substantive changes.
Proposed paragraph (a)(1), like our current regulations, states
``ONRR may monitor, review, and audit the royalties you report, and, if
ONRR determines that your reported value is inconsistent with the
requirements of this subpart, ONRR will direct you to use a different
measure of royalty value . . . .'' However, we propose to add paragraph
(a)(1) that states in addition to directing you to use a different
measure of value, we also may decide your value under Sec. 1206.144 as
we discuss below.
Proposed paragraph (b), like our current regulations, explains
``[w]hen the provisions in this subpart refer to gross proceeds, in
conducting reviews and audits, ONRR will examine if your or your
affiliate's contract reflects the total consideration actually
transferred, either directly or indirectly, from the buyer to you or
your affiliate for the gas, residue gas, or gas plant products.''
However, we propose to add a new paragraph (b) that if ONRR determines
a contract does not reflect the total consideration, ONRR may decide
your value under Sec. 1206.144 as we discuss below.
Proposed paragraph (c) broadly defines three circumstances when
ONRR will calculate the value of your gas using the method specified in
the new proposed ``default'' valuation Sec. 1206.144. During its
compliance activities, ONRR encounters a wide range of situations in
which lessees have inaccurately calculated value. By broadly defining
the circumstances in which ONRR may calculate value, this proposed rule
ensures ONRR can fulfill its statutory mandate under FOGRMA to ensure
that lessees accurately calculate, report, and pay royalties (30 U.S.C.
1701 and 1711).
Proposed paragraphs (c)(1) and (c)(2) contain the provisions
regarding misconduct and breach of the duty to market in current 30 CFR
1206.152(b)(1)(i) and 1206.153(b)(1)(iii). Under the current
regulations, if ONRR determines there is misconduct between the
parties, or that the lessee has breached its duty to market, then the
lessee must value its gas under the current benchmarks for non-arm's-
length sales of gas in 30 CFR 1206.152(c)(2) or (c)(3) (unprocessed
gas) and 1206.153(c)(2) or (c)(3) (processed gas). However, as we
discuss above, ONRR proposes to eliminate the benchmarks in this
rulemaking. We propose instead that if ONRR determines there is
misconduct between the parties to a contract or the lessee has breached
its duty to market, we may decide your value under Sec. 1206.144 as we
discuss below.
As we discuss above in proposed Sec. 1206.20, misconduct, for
purposes of proposed paragraph (c)(1), means any failure to perform a
duty owed to the United States under a statute, regulation, or lease,
or unlawful or improper behavior regardless of the mental state of the
lessee or any individual employed by, or associated with, the lessee.
Misconduct, in this subpart, would be different than, and in addition
to, any violations subject to civil penalties under FOGRMA, 30 U.S.C.
1719, and its implementing regulations in part 1241 of this chapter.
Behavior that constitutes misconduct, under this part 1206, would not
need to be willful, knowing, voluntary, or intentional. This is a
valuation mechanism, not an enforcement tool. Under this proposed rule,
if ONRR determines that misconduct has occurred, ONRR will calculate
value under Sec. 1206.144. However, if ONRR determines the misconduct
was knowing or willful, it also could pursue civil penalties under part
1241 of this chapter.
Under proposed paragraph (c)(2), ONRR defines what is a breach of
the duty to market. The proposed rule specifies that ONRR may determine
value under Sec. 1206.144 if a lessee sells gas, residue gas, or gas
plant products at an unreasonably low price. The proposed rule explains
what ONRR could consider an ``unreasonably low'' price. A lessee has a
duty to market gas for the mutual benefit of the United States, as
lessor, and the lessee. An unreasonably low price may reflect a failure
of the lessee to perform that duty. Proposed paragraph (a)(2) defines a
sales price as ``unreasonably low'' ``if it is 10 percent less than the
lowest reasonable measures of market price, including, but not limited
to, index prices and prices reported to ONRR for like-quality gas,
residue gas, or gas plant products.'' ONRR's authority to exercise this
provision is discretionary; ONRR ``may'' decide your value if it
determines your price is unreasonably low. In exercising its
discretion, ONRR may consider any information that shows a price
appears unreasonably low, and, thus, is not an accurate reflection of
fair market value.
ONRR also proposes a new paragraph (c)(3). Under proposed paragraph
(c)(3), ONRR may value your gas, residue gas, or gas plant products
under Sec. 1206.144 if ONRR cannot determine if you properly valued
your gas, residue gas, or gas plant products under Sec. 1206.141 or
Sec. 1206.142 for any reason. This is a broad ``catch-all'' provision
ONRR may
[[Page 622]]
use to decide the value of gas, residue gas, or gas plant products when
it cannot determine if a lessee properly valued its production. ONRR
will exercise this discretionary authority to meet its mandate under 30
U.S.C. 1711 to ensure accurate accounting for Federal oil and gas
royalties under the different circumstances it encounters during its
compliance verification activities. It is the lessee's responsibility
to provide ONRR with information sufficient for us to ensure that
royalties are accurately calculated. Under this provision, ONRR will
still meet its statutory mandate even when a lessee fails to provide
sufficient information. However, like proposed paragraph (c)(1) of this
section, this is an ONRR valuation mechanism that is in addition to any
civil penalty authority ONRR has under part 1241 of this chapter.
We propose a new paragraph (g)(1) that requires the lessee or its
affiliate to make all contracts in writing before it can use the
contracts as the basis for the lessee's valuation of its gas produced
from Federal leases. This proposed requirement will apply to any
contract revisions or amendments. Further, ONRR proposes that all
parties to the contract must sign the contracts, contract revisions, or
amendments before lessees can use them as the basis for the lessee's
valuation of its gas under these regulations.
ONRR believes this proposed requirement is critical to the proper
application of the valuation regulations. Lessees should provide to
ONRR the actual, written contracts signed by all parties because those
contracts document the very transactions on which the regulations
require lessees to base values and allowances. Without the applicable
sales, transportation, and/or processing contracts, neither the lessee
nor ONRR can verify that Federal royalties are properly paid. Because
ONRR would only require a lessee to provide its actual contractual
arrangements that it uses to conduct its business, this requirement
should place no burden on a lessee.
ONRR proposes a new paragraph (g)(2) providing that ONRR may decide
the value of a lessee's gas if the lessee or its affiliate fails to
make all contracts, contract revisions, or amendments in writing. If
the lessee cannot produce the written, signed contracts that would
otherwise serve as the basis of the lessee's valuation of its gas under
the regulations, ONRR may decide to determine the appropriate value of
the lessee's gas under newly proposed Sec. 1206.144 as we discuss
below.
Finally, ONRR proposes to add paragraph (g)(3) to make clear the
new provision requiring contracts to be in writing and signed by all
parties is in addition to any other recordkeeping requirements the
lessee must satisfy under this title, and that this new requirement
supersedes any provision in this title to the contrary.
1206.144 How will ONRR determine the value of my gas for royalty
purposes?
ONRR proposes a new ``default'' valuation Sec. 1206.144 that ONRR
may use to value your gas, residue gas, or gas plant products for
royalty purposes. Because we propose the same default provision for
federal oil, please refer to Sec. 1206.105 above for more information.
1206.145 What records must I keep to support my calculations of royalty
under this subpart?
1206.146 What are my responsibilities to place production into
marketable condition and to market production?
1206.147 When is an ONRR audit, review, reconciliation, monitoring, or
other like process considered final?
1206.148 How do I request a valuation determination or guidance?
See discussion below.
1206.149 Does ONRR protect information I provide?
1206.150 How do I determine royalty quantity and quality?
ONRR proposes to rewrite in Plain Language the regulations for
recordkeeping, marketable condition and marketing, audit,
confidentiality, and quantity and quality requirements and procedures.
Also, ONRR proposes to make these sections consistent with other
product valuation regulations, such as the geothermal and Federal oil
regulations. In addition, rather than repeat the requirements or
procedures in each applicable section of this rule, ONRR proposes to
have these sections apply to this entire subpart. The substantive
requirements remain unchanged.
1206.148 How do I request a valuation determination or guidance?
ONRR proposes a new Sec. 1206.148 on how to request a valuation
determination or guidance. This section is the same as Sec. 1206.108
applicable to Federal oil we discuss above, with several substantive
changes. Proposed Sec. 1206.148 replaces and expands the provisions
contained in current 30 CFR 1206.152(g) and 1206.153(g). The newly
proposed section provides greater clarity on the process lessees may
use to request valuation guidance and determinations, as well as on the
effect of ONRR's response to such requests. Adding proposed Sec.
1206.148 will make the procedures for gas valuation requests consistent
with the procedures ONRR proposes for Federal oil and Federal and
Indian coal.
Under proposed paragraph (a), a lessee may request a valuation
determination or guidance from ONRR regarding any gas produced.
Paragraph (a)(1) through (3) explains that the lessee's request must be
in writing; identify all leases involved, all interest owners in the
leases, and the operator(s) for those leases; and completely explain
all relevant facts. In addition, under paragraphs (a)(4) through (6), a
lessee must provide all relevant documents, its analysis of the
issue(s), citations to all relevant precedents, including adverse
precedents, and its proposed valuation method.
In response to a lessee's request, under proposed paragraph (b),
ONRR may (1) decide that it will issue guidance, (2) inform the lessee
in writing that it will not provide a determination or guidance, or (3)
request that the Assistant Secretary for Policy, Management, and Budget
issue a determination. This proposal changes the current Federal oil
regulations under 30 CFR 1206.107(b), which has caused confusion over
whether an ONRR-issued determination is a binding appealable order or
non-appealable guidance. Under this proposed rule, ONRR clarifies that
we only issue non-binding guidance for valuation of Federal oil and gas
and Federal and Indian coal. This proposal is consistent with ONRR's
existing practice of having only the Assistant Secretary sign decisions
that are binding on the Department. Also, ONRR proposes to remove the
regulatory language that we will ``reply to requests expeditiously.''
Our practice is to reply as quickly as possible, so we do not make it a
regulatory requirement.
Proposed paragraphs (b)(3)(i) and (ii) identify situations in which
ONRR and the Assistant Secretary typically do not provide a
determination or guidance, including, but not limited to, requests for
guidance on hypothetical situations and matters that are the subject of
pending litigation or administrative appeals.
Under proposed paragraph (c)(1), a determination the Assistant
Secretary of Policy, Management and Budget signs binds both the lessee
and ONRR unless the Assistant Secretary modifies or rescinds the
determination. After the Assistant Secretary issues a determination,
under proposed paragraph (c)(2), the lessee must make
[[Page 623]]
any adjustments to its royalty payments that follow from the
determination. If the lessee owes additional royalties, it must pay the
additional royalties due plus late payment interest calculated under
Sec. Sec. 1218.54 and 1218.102 of this chapter. In addition, proposed
paragraph (c)(3) explains that a determination the Assistant Secretary
signs is the final action of the Department and is subject to judicial
review under 5 U.S.C. 701-706.
Proposed paragraph (d) explains that, if ONRR issues guidance, the
guidance is not binding on ONRR, delegated States, or the lessee with
respect to the specific situation addressed in the guidance. This is a
change from the current Federal oil regulation at 30 CFR 1206.107(d)
that makes a determination ONRR issues binding on ONRR and delegated
States but not the lessee. Moreover, guidance, ONRR's decision whether
to issue guidance, and ONRR's decision whether to request a
determination by the Assistant Secretary would not be appealable
decisions or orders under 30 CFR part 1290. This is the same as current
30 CFR 1206.107(d)(1). However, as provided under current 30 CFR
1206.107(d)(2), under proposed paragraph (d)(2) of this section, if
ONRR issues an order requiring the lessee to pay royalty on the same
basis as the guidance, the lessee could appeal the order under 30 CFR
part 1290.
Under proposed paragraph (e), ONRR or the Assistant Secretary may
use any of the applicable criteria in this subpart to make a
determination or provide guidance. Also, under proposed paragraph (f),
if a statute or regulation on which ONRR based any determination or
guidance is changed, the changed statute or regulation takes precedence
over the determination or guidance after the effective date of the
statute or regulation, regardless of whether ONRR or the Assistant
Secretary modifies or rescinds the determination or guidance.
Therefore, under this proposed provision, determinations and guidance
are not open-ended.
1206.151 How do I perform accounting for comparison?
ONRR proposes to move the regulations in current 30 CFR 1206.155 to
proposed Sec. 1206.151, but we rewrite this section in Plain Language.
This section requires a lessee to pay royalties on the greater of the
value of the unprocessed gas or the value of its processed gas if the
lessee, its affiliate, a person to whom the lessee transferred gas
under a non-arm's-length contract, or a person to whom the lessee
transferred gas without a contract processes the lessee's or its
affiliate's gas and does not sell the residue gas at arm's length.
However, ONRR requests comments on whether we need this proposed
requirement for two reasons. First, proposed Sec. Sec. 1206.142 and
1206.143 of this subpart recognize the real market value of gas today
is the combined value of its constituent components--residue gas and
gas plant products. And, the proposed regulations value gas sold on
that basis as processed gas. There appears to be a limited market for
unprocessed gas, unless it is sold based upon the constituent products
contained therein, hence accounting for comparison may not be needed.
Second, because the criteria that triggers dual accounting--a non-
arm's-length sale of residue gas after processing--is not used to value
gas under this proposed rule, dual accounting may no longer be
appropriate because the residue gas is valued based on the first arm's-
length sale or index-based option.
ONRR also proposes to keep the requirement in current 30 CFR
1206.155 that lessees must perform dual accounting if required by lease
terms. ONRR believes this provision is consistent with proposed Sec.
1206.140(c)(4), which specifically recognizes the primacy of lease
terms over the terms of the regulations when they are inconsistent.
Before we discuss each section of proposed Sec. Sec. 1206.152
through 1206.158 regarding transportation allowances, we believe it is
helpful to discuss some general changes we make. The proposed
regulations move the current regulations regarding transportation
allowances from 30 CFR 1206.156 and 1206.157 to proposed Sec. Sec.
1206.152 through 1206.158. The proposed gas transportation allowance
regulations are changed, primarily in structure, but there also are a
few substantive changes. The structure of the proposed gas
transportation allowance regulations is modeled after the current
Federal oil transportation allowance regulations to achieve consistency
between the two. In most cases, the regulatory requirements do not
change. We reorganize the current provisions and rewrite them in Plain
Language. Like the current oil transportation allowance regulations,
this structure provides more regulatory section headings, better
organization, and greater visibility to locate regulatory requirements
applicable to the lessee's particular transportation allowance
situations. Also, we reorganize or combine many paragraphs that were
embedded within a current section into a new section for greater
visibility. We propose to segregate individual multiple requirements
within paragraphs into separate paragraphs to improve visibility and
identification.
1206.152 What general transportation allowance requirements apply to
me?
Proposed Sec. 1206.152 retains the provisions in current Sec.
1206.156 (``Transportation allowances--general''), makes Federal gas
regulations consistent with Federal oil regulations, and consolidates
provisions applicable to both arm's-length and non-arm's-length
transportation in the current regulations rather than repeating those
provisions in the respective sections explaining those allowances. We
also rewrite the current regulations in Plain Language and only discuss
substantive changes and additions below.
Proposed paragraph (a) contains the same requirements as current
Sec. 1206.156(a) and includes a new provision that ``[y]ou may not
deduct transportation costs you incur to move a particular volume of
production to reduce royalties you owe on production for which you did
not incur those costs.'' Consistent with current regulations, this
provision prevents the lessee from claiming transportation costs
incurred for a segment of transportation when the gas did not actually
flow on that segment. A lessee could only claim transportation costs
attributable to the actual movement of the lease production on that
transportation segment.
We also propose new paragraphs (a)(1) and (a)(2)(i), which are
consistent with the current Federal oil rule Sec. 1206.109(a)(2). New
paragraph (a)(1) states you may take a transportation allowance when
you value unprocessed gas under Sec. 1206.141(b) or residue gas and
gas plant products under Sec. 1206.142(b) based on a sale at a point
off the lease, unit, or communitized area where the gas is produced.
New paragraph (a)(2)(i) states that you may take a transportation
allowance when the movement to the sales point is not gathering.
Neither change to the current rule is substantive because both codify
existing practice and case law.
Proposed new paragraph (a)(2)(ii) states that ``[f]or gas produced
on the OCS, the movement of gas from the wellhead to the first platform
is not transportation.'' It is well established that the movement of
oil and gas that ONRR determines is ``gathering'' is not allowable as a
transportation allowance. California Co. v. Udall, 296 F.2d 384 (D.C.
Cir. 1961); Kerr-McGee Corp., 147 IBLA 277 (1999). However, on May 20,
1999, the then-Associate Director for the former MMS's Royalty
Management
[[Page 624]]
Program issued ``Guidance for Determining Transportation Allowances for
Production from Leases in Water Depths Greater Than 200 Meters'' (Deep
Water Policy). The Deep Water Policy provides the following guidelines:
(1) Current regulations must be followed; (2) movement costs are
allocated between royalty and non-royalty bearing substances; (3)
movement prior to a central accumulation point is considered gathering,
movement beyond the point is considered transportation; (4) leases and
units are treated similarly; (5) the movement is to a facility that is
not located on a lease adjacent to the lease on which the production
originates; and (6) allowances for subsea completions not located in
water deeper than 200 meters are considered on a case-by-case basis.
Both the current Federal oil and gas valuation rules define
gathering as ``the movement of lease production to a central
accumulation or treatment point on the lease, unit, or communitized
area, or to a central accumulation or treatment point off the lease,
unit, or communitized area that BLM or BSEE approves for onshore and
offshore leases, respectively.'' 30 CFR 1206.101 (Federal oil) and
1206.151 (Federal gas). Under the Deep Water Policy, ONRR considered a
subsea manifold located on the OCS in deep water to be a ``central
accumulation point'' regardless of whether it was actually a central
accumulation or treatment point as ONRR's regulations require. Since
ONRR issued the Deep Water Policy, lessees have been deducting the
costs of moving bulk production from the subsea manifold to the
platform where the oil and gas first surface. In addition, lessees have
attempted to expand the Deep Water Policy to deem subsea wellheads
``central accumulation points'' and take transportation allowances from
the sea bed floor to the first platform where the bulk production
surfaces. Thus, lessees have taken transportation allowances under the
Deep Water Policy, in some instances, for movement ONRR considers non-
deductible ``gathering'' under its regulations.
In addition, the Interior Board of Land Appeals (IBLA) has
concluded there are three definitive attributes of gas gathering lines:
(1) They move lease production to a central accumulation point; (2)
they connect to gas wells; and (3) they bring gas by separate and
individual lines to a central point where it is delivered into a single
line. Kerr-McGee Corp., 147 IBLA at 282 (citations omitted). In Kerr-
McGee, the IBLA stated that ``even though production is moved across
lease boundaries, because it is treated and sold on adjacent leases the
costs of moving it there are properly regarded as gathering, not
transportation.'' Id. at 283 (citations omitted). Under Kerr-McGee,
almost all of the movement the Deep Water Policy allows as a
transportation allowance is, in actuality, non-deductible ``gathering''
under ONRR's current valuation regulations.
We have determined that the Deep Water Policy is inconsistent with
our regulatory definition of gathering and Departmental decisions
interpreting that term. Therefore, we propose to rescind the Deep Water
Policy in this rulemaking. We propose to accomplish this by making two
changes. First, consistent with Kerr-McGee, we propose to add to the
definition of ``gathering'' that any movement of bulk production from
the wellhead to a platform offshore is gathering, not allowable
transportation. Second, we propose to add a new paragraph (a)(2)(ii) to
this section that states ``[f]or gas produced on the OCS, the movement
of gas from the wellhead to the first platform is not transportation.''
We also make this change to proposed Federal oil Sec.
1206.110(a)(2)(ii).
Proposed paragraph (b) of this section contains and consolidates
current requirements in 30 CFR 1206.156(b) and 1206.157(a)(2) and
(b)(3) regarding allocation of transportations costs based on your or
your affiliate's cost of transporting each product if you transport one
or more products in the gaseous phase in a transportation system.
Proposed paragraph (c)(1) contains and consolidates current
requirements in 30 CFR 1206.157(a)(2) and (b)(4) which all apply to
allocation of transportations costs when you or your affiliate
transport both gaseous and liquid products in the same transportation
system.
Under proposed paragraph (d), if you value unprocessed gas under
Sec. 1206.141(c) or residue gas and gas plant products under Sec.
1206.142(d)--the index-based valuation options--you may not take a
transportation allowance. This is because the index-based valuation
provisions already incorporate the costs of transportation.
Proposed paragraph (e)(1), eliminates the current provision
allowing lessees to request transportation allowances in excess of 50
percent of the sales value of the unprocessed gas, residue gas, or
NGLs. Currently, ONRR limits transportation allowances and factors to
50 percent of the sales value of unprocessed gas, residue gas, or gas
plant products unless we approve an exception to the limitation. To
ensure a fair return to the public and to limit ONRR's administrative
costs to process such requests, the proposed regulation eliminates the
exception to the 50-percent limit. ONRR believes the current 50-percent
limit on transportation-related costs is adequate in the vast majority
of transportation situations. Thus, paragraph (e)(2) provides that any
existing approvals for the exception to the limitation terminate on the
effective date of the final rule. We will not grandfather any existing
approval to exceed the 50-percent limit.
Proposed paragraph (f) continues the current requirement under 30
CFR 1206.157(a)(4), applicable to arm's-length transportation, that
lessees must express transportation allowances for residue gas, gas
plant products, or unprocessed gas in a dollar-value equivalent. We
propose to also apply this requirement to non-arm's-length
transportation consistent with existing practice. We further propose
that if your or your affiliate's payments for transportation under a
contract are not in dollars-per-unit, you must convert the
consideration you or your affiliate paid to its dollar-value
equivalent.
Like the default provision for valuation we discuss above under
Sec. 1206.143(c), proposed paragraphs (g)(1), (2), and (3) provide
that ONRR may determine your transportation allowance under Sec.
1206.144, if: (1) There is misconduct by or between the contracting
parties; (2) the total consideration the lessee or its affiliate pays
under an arm's-length contract does not reflect the reasonable cost of
transportation because the lessee breached its duty to market the
unprocessed gas, residue gas, or gas plant products for the mutual
benefit of the lessee and the lessor by transporting such products at a
cost that is unreasonably high; or (3) ONRR cannot determine if the
lessee properly calculated a transportation allowance under Sec.
1206.153 or Sec. 1206.154, for any reason. Under proposed paragraph
(g)(2), ONRR may consider an allowance to be unreasonably high if it is
10-percent higher than the highest reasonable measures of
transportation costs, including, but not limited to, transportation
allowances lessees and others report to ONRR and tariffs for gas,
residue gas, or gas plant products transported through the same system.
Finally, we propose a new provision under paragraph (h) to make
clear that you do not need ONRR's approval before reporting a
transportation allowance for costs that you incur. This provision is in
the current regulations that apply to arm's-length transportation at 30
CFR 1206.157(a), but we propose to apply it to non-arm's-length
[[Page 625]]
transportation as well. This is consistent with existing practice.
1206.153 How do I determine a transportation allowance if I have an
arm's-length transportation contract?
Proposed Sec. 1206.153 explains how lessees must determine a
transportation allowance under arm's-length transportation contracts.
As we discuss above, we propose to restructure this section for
consistency with the Federal oil transportation allowance regulations.
In addition, we move the requirements for non-arm's-length
transportation allowances to a separate Sec. 1206.154.
Proposed paragraph (a)(1) states that this section applies to both
the lessee and its affiliate if the lessee chooses to use the
affiliate's arm's-length sales contract for valuation and if that
affiliate incurs transportation costs under an arm's-length
transportation contract to move the lease production to the sales
point. However, ONRR will determine your transportation allowance under
Sec. 1206.152(g) if ONRR determines there is misconduct, the arm's-
length transportation cost is unreasonably high, or ONRR cannot
determine if your transportation allowance is proper. This provision
gives ONRR greater discretion and flexibility to determine
transportation allowances (for example, when arm's-length
transportation service providers charge bundled fees). See the
discussion of bundled fees in proposed Sec. 1206.141 above.
ONRR proposes to eliminate the provision in current 30 CFR
1206.157(a)(5) that allows lessees to report transportation costs, in
certain circumstances, as a transportation factor. Rather, we propose
that a lessee must report separately all transportation costs under
both arm's-length and non-arm's-length sales contracts as a
transportation allowance on Form ONRR-2014. ONRR believes that
requiring lessees to report all deductions for transportation costs
separately as allowances on Form ONRR-2014 is more transparent,
supports ONRR's increased data mining efforts to promote accuracy, and
assists State and Federal auditors with their compliance work. We
propose this same change for oil produced from Federal lands.
Proposed paragraph (b) allows a lessee to include the same costs we
allow under current 30 CFR 1206.157(f) in its transportation allowance.
Under new paragraph (b)(11), we also propose that a lessee may include
in its transportation allowance hurricane surcharges the lessee or its
affiliate pay. This proposal is consistent with existing practice.
Under proposed paragraph (c), we specify transportation costs we
would not allow a lessee to include in its transportation allowance.
These non-allowable costs remain mostly the same as those we currently
disallow under 30 CFR 1206.157(g). We believe it is already clear the
cost of boosting gas (e.g. recompressing residue gas at the plant after
processing) is not a deductible cost of transportation under current 30
CFR 1202.151(b) and the Assistant Secretary's decision at issue in
Devon. Nevertheless, proposed paragraph (c)(8) specifically states that
the costs of boosting residue gas are not allowable as a cost of
transportation.
Finally, we propose a new paragraph (d) that applies if you have no
written contract for the arm's-length transportation of gas. In that
case, ONRR determines your transportation allowance under proposed
Sec. 1206.144. Under this proposal, you have to propose to ONRR a
method to determine the allowance using the procedures in Sec.
1206.148(a) and could use that method until ONRR issues its
determination. This paragraph only applies when there is no contract
for arm's-length transportation. Thus, it would not apply if lessees
perform their own transportation. Rather, Sec. 1206.154 regarding non-
arm's-length transportation allowances applies.
1206.154 How do I determine a transportation allowance if I have a non-
arm's-length transportation contract?
We propose Sec. 1206.154 as a separate section explaining how to
calculate transportation allowances under a non-arm's-length contract,
such as where the lessee ships its production through its own pipeline
or through a pipeline its affiliate owns. Under proposed paragraph (a),
ONRR continues the provision in current 30 CFR 1206.157(b) that does
not recognize contracts between the lessee and its affiliate or any
other person without opposing economic interests regarding that
contract. Like the current regulations, you will determine non-arm's-
length transportation allowances based on your actual costs or the
actual costs of the affiliated pipeline owner.
Proposed paragraph (b) generally explains costs you may include in
your transportation allowance. Paragraph (b)(1) explains the lessee's
or its affiliate's actual costs include capital costs and operating and
maintenance expenses under paragraphs (e), (f), and (g) of this
section. Proposed paragraph (b)(2) explains you also could include
overhead under paragraph (h) of this section. Under proposed paragraph
(b)(3), we revise the current regulation to clarify the methodology for
the two options to calculate depreciation. Under this proposed
rulemaking, we allow lessees to choose between depreciation and a
return on undepreciated capital investment under paragraph (i)(1) of
this section, or a cost equal to a return on the initial depreciable
capital investment in the transportation system under paragraph (i)(2)
of this section. Finally, paragraph (b)(4) allows the lessee to
continue to claim a rate of return on the reasonable salvage value of
the transportation system after it is fully depreciated. For example,
if the pipeline had a salvage value of 5 percent, the lessee may claim
a rate of return on 5 percent of the system value, even though we would
allow no further depreciation. See the discussion of reasonable salvage
value in proposed Sec. 1206.112(i)(1)(iii).
We also propose to remove the provisions of current Sec.
1206.175(b)(5) that allow a lessee with a non-arm's-length contract to
use FERC or State-regulatory-agency approved tariffs as an exception
from the requirement to calculate actual costs. We remove this
provision to make it consistent with the current Federal oil valuation
regulations. Under the proposed rule, lessees must compute their actual
costs to determine transportation allowances under non-arm's-length
contracts even when a regulatory agency has approved a tariff.
Proposed paragraph (c) further explains the transportation costs
you may and may not include in a transportation allowance. Proposed
paragraph (c)(1) states that, to the extent that you have not already
included in your transportation allowances the allowable costs under
paragraphs (e) through (g) of this section, you may include in your
allowance the actual transportation costs we list under Sec.
1206.153(b)(2), (5), and (6) of this subpart (Gas supply realignment
(GSR) costs, Gas Research Institute (GRI) fees, and Annual Charge
Adjustment (ACA) fees that FERC imposes). ONRR proposes to disallow the
remaining costs we allow a lessee to include in arm's-length
transportation allowances under Sec. 1206.153(b) because the lessee
would not or should not ordinarily incur the costs as a pipeline owner
or be charged for those costs by its affiliate. However, there may be
instances when specific costs integral to transportation could be
included in the pipeline owner's operating and maintenance costs. ONRR
invites comments on what types of costs, other than those identified in
Sec. 1206.153(b)(2), (5), and (6), may be actual costs of
transportation
[[Page 626]]
under non-arm's-length transportation arrangements.
ONRR also proposes to eliminate the current provision allowing
lessees to deduct the costs of pipeline losses, both actual and
theoretical, under non-arm's-length transportation situations. These
regulations prohibited actual or theoretical pipeline losses prior to
the 1997 gas transportation allowance revisions that incorporated new
costs resulting from FERC Order No. 636. The advent of Order No. 636
should not have had any bearing on such non-arm's-length costs.
Therefore, ONRR proposes to remove this provision. ONRR recognizes that
pipeline losses are distinct from transportation fuel that is used on a
pipeline to power compressors used for actual transportation. Under the
proposal, ONRR continues to permit lessees to claim an allowance for
actual fuel used for qualifying transportation purposes. In addition,
we continue to disallow fuel for non-approved off-lease compressors and
off-lease fuel for other processes necessary to place lease production
in marketable condition.
Proposed paragraph (c)(2) explains that we do not allow a lessee to
include in its non-arm's-length transportation allowances the same
costs we do not allow to be included in arm's-length transportation
allowances under proposed Sec. 1206.153(c).
Like the arm's-length provision, proposed paragraph (d) states that
for non-arm's-length transportation allowances, the lessee may not
duplicate allowable transportation costs when it calculates an
allowance. For example, if the lessee includes GRI costs in its
operating costs under paragraph (b), it may not also include those
costs under paragraph (c).
Proposed paragraphs (e) through (h) contain the same requirements
as current 30 CFR 1206.157(b)(2)(i), (ii), and (iii), but we rewrite
the provisions in Plain Language and make them consistent with the
current Federal oil regulations.
Proposed paragraph (i) retains the requirements of current 30 CFR
1206.157(b)(2)(iv) regarding depreciation, but we rewrite those
provisions in Plain Language and make them consistent with the Federal
oil regulations. ONRR proposes to eliminate the reference to
transportation facilities first placed in service after March 1, 1988.
When ONRR published its Federal gas valuation regulations on January
15, 1988, it changed the requirements necessary to receive
transportation and processing allowances. In recognition that certain
transportation and processing facilities had been given approval prior
to those regulations' effective date (March 15, 1988), ONRR made the
new requirements apply only to facilities that were placed in service
on or after the effective date of those regulations. Now more than
twenty years later, ONRR believes that none of the facilities placed in
service before March 15, 1988, are still eligible for depreciation
under the requirements in effect prior to March 15, 1988. Therefore, we
propose to remove this outdated language from the proposed regulations.
Under paragraph (i)(3), ONRR proposes to revise the rate of return
from 1.3 times the Standard & Poor's BBB bond rate in current 30 CFR
1206.157(b)(2)(v) to the rate without a multiplier, in other words 1
times the BBB bond rate. We make the same change to Federal oil, so
please refer to our discussion of proposed Sec. 1206.112(i)(3).
1206.155 What are my reporting requirements under an arm's-length
transportation contract?
This section would contain essentially the same provisions as
current 30 CFR 1206.157(c)(1). However, ONRR proposes to add the term
``affiliate'' to paragraph (b). Under the new proposed valuation
provisions, which use an affiliate's arm's-length sales contract, ONRR
allows a transportation allowance to the arm's-length sales point and,
therefore, needs the associated transportation contracts. In addition,
ONRR proposes to eliminate the reference to allowances in effect prior
to March 1, 1988, under current 30 CFR 1206.157(c)(1)(iii). As stated
above, ONRR believes that none of facilities predating the 1988 rule
change are still eligible for depreciation under the requirements in
effect prior to March 15, 1988. Therefore, we are removing this
language from the proposed regulations.
1206.156 What are my reporting requirements under a non-arm's-length
transportation contract?
This section contains essentially the same provisions as current 30
CFR 1206.157(c)(2). In this proposed rule, ONRR eliminates the
reference in current 30 CFR 1206.157(c)(2)(v) to allowances in effect
prior to March 1, 1988.
1206.157 What interest or penalties apply if I improperly report a
transportation allowance?
Under proposed Sec. 1206.157, ONRR consolidates the penalty and
interest provisions for improper allowances. Currently, such provisions
are contained under both the general transportation and determination
of transportation allowances sections of the regulations. Proposed
paragraph (a)(1) slightly modifies current 30 CFR 1206.156(d) by using
the term ``unauthorized'' in the context of ``If ONRR determines that
you took an unauthorized transportation allowance, then you must pay
any additional royalties due. . . .'' However, this change would not
alter the meaning of the current provisions. Examples of unauthorized
transportation allowances include, but are not limited to, exceeding
the 50-percent limitation, including costs necessary to place the gas
into marketable condition, or including other costs that are not
integral to the transportation of lease production. Proposed paragraph
(a)(2) states that a lessee may be entitled to a credit with interest
if it understated its transportation allowance. This provision amends
current 30 CFR 1206.157(e) to comply with RSFA's provision that
entitles lessees to interest on overpayments (30 U.S.C. 1721(h)).
Proposed paragraph (b) states that, if the lessee deducts a
transportation allowance that exceeds 50 percent of the value of the
gas, residue gas, or gas plant products transported, the lessee must
pay late payment interest on the excess allowance amount taken from the
date that amount is taken until the date it paid the additional
royalties due. This changes the current requirement that interest is
calculated from the date the allowance is taken until the lessee files
a request for an exception. This change results from ONRR proposing to
eliminate allowance exceptions.
Proposed paragraph (c) restates current 30 CFR 1206.156(d).
1206.158 What reporting adjustments must I make for transportation
allowances?
Section 1206.158 restates the requirements of current 30 CFR
1206.157(e), except we rewrite the provisions in Plain Language.
1206.159 What general processing allowances requirements apply to me?
Like the amendments to transportation allowances discussed above,
ONRR proposes to rewrite the current processing allowance regulations
at 30 CFR 1206.158 in Plain Language, make them consistent with Federal
oil, and reorganize them for clarity and visibility. We are not
planning to make any substantive changes in proposed paragraph (a)(1)
and paragraph (b); they will contain the same provisions as current 30
CFR 1206.158 (a) and (b). However, we
[[Page 627]]
propose to add a new provision under paragraph (a)(2) to make clear
that you do not need ONRR's approval before reporting a processing
allowance for costs that you incur for arm's-length or non-arm's-length
allowances. This is consistent with existing practice.
Proposed paragraph (c) continues the requirements of current 30 CFR
1206.158(c), with two substantive changes and one clarification to
current 30 CFR 1206.158(c)(1). Current paragraph 1206.158 (c)(1) states
that ``Except as provided in paragraph (d)(2) of this section, the
processing allowance shall not be applied against the value of the
residue gas. Where there is no residue gas ONRR may designate an
appropriate gas plant product against which no allowance may be
applied.'' We are removing the second sentence because we do not
believe ONRR ever used this provision.
ONRR proposes to eliminate the exception under current 30 CFR
1206.158 (c)(3) allowing a lessee to request ONRR approval of a
processing allowance that exceeds 66\2/3\ percent of the value of the
plant products. We also propose to eliminate the provision allowing a
lessee to request an extraordinary processing cost allowance under
current 30 CFR 1206.158(d)(2). ONRR also proposes to terminate any
approvals for the exception under proposed paragraph (c)(3) and the
extraordinary cost processing allowance under proposed paragraph (c)(4)
as of the effective date of the rule. Thus, we propose not to
grandfather previously approved exceptions or extraordinary allowances.
ONRR proposes these changes because, as with transportation allowances,
ONRR believes the current 66\2/3\ percent limit on processing-related
costs is adequate in the vast majority of situations. To date, we only
have approved two extraordinary processing cost allowances. Given the
age of the plants and improvements in technology, ONRR believes such
extraordinary cost allowances no longer reflect current conditions.
Furthermore, ONRR believes the current 66\2/3\ percent limitation on
gas plant products ensures a fair return to the public.
Proposed paragraph (d) explains and clarifies that we continue to
disallow deductions for costs necessary to place gas into marketable
condition. ONRR proposes to retain the existing requirements of current
30 CFR 1206.158(d)(1) but proposes to recodify them as Sec.
1206.159(d)(1), (2), (3), and (4). Also, the proposed rule makes clear
that any cost a lessee incurs for stabilizing condensate or recovering
gas vapors from condensate or oil is disallowed. The methods industry
employs to perform these services are not within the proper definition
of ``processing'' under these regulations and are, in fact, costs
incurred to place the condensate or oil into marketable condition.
Likewise, we currently analyze whether hydrocarbon dew point controls
are actually functions that fall within the definition of
``processing'' under the regulations before qualifying for a processing
allowance against the value of the liquids recovered. In conjunction
with these efforts to clarify the costs that qualify as a processing
allowance, ONRR proposes to add Joule-Thomson Units (JT Units) used to
recover NGLs from gas to the definition of ``processing'' under
proposed Sec. 1206.20, regardless of the location of the JT Unit.
1206.160 How do I determine a processing allowance, if I have an arm's-
length processing contract?
ONRR proposes this new section, which is essentially the same as
current 30 CFR 1206.159(a), with no material modifications, except we
add a new paragraph (c) we discuss below. Like transportation
allowances, we are moving the requirements for non-arm's-length
processing allowances to a separate Sec. 1206.161. Because the
requirements for determining processing allowances under an arm's-
length contract are essentially the same as those for determining
transportation allowances under an arm's-length contract, we make the
same changes to processing allowances in this section as those we
propose for arm's-length transportation allowances. Refer to the
preamble discussion of Sec. 1206.153 for an explanation of the
changes.
We propose a new paragraph (c) that applies if you have no written
contract for arm's-length processing of gas. In that case, ONRR will
determine your processing allowance under Sec. 1206.144. You will have
to propose to ONRR a method to determine the allowance using the
procedures in Sec. 1206.148(a) and may use that method until ONRR
issues a determination. This proposed paragraph only applies if there
is no contract for arm's-length processing. It does not apply if a
lessee performs its own processing. In that case, Sec. 1206.161
applies.
ONRR also proposes new Sec. 1206.161 through Sec. 1206.165 to
subpart D to codify and enhance current Federal gas valuation
practices.
1206.161 How do I determine a processing allowance if I have a non-
arm's-length processing contract?
This section contains the same requirements as current 30 CFR
1206.159(b). Because the requirements for determining processing
allowances under a non-arm's-length contract are essentially the same
as those for determining transportation allowances under a non-arm's-
length contract, we make the same changes to processing allowances in
this section as those we propose for non-arm's-length transportation
allowances. Refer to the preamble discussion of Sec. 1206.154 for an
explanation of the changes.
ONRR proposes one material change to the current regulatory
requirements. Under proposed paragraph (b)(4), we allow the lessee to
continue claiming a rate of return on the reasonable salvage value of a
processing plant after it is fully depreciated. For example, if the
plant had a salvage value of 5 percent, the lessee could claim a rate
of return on 5 percent of the plant value, even though we would allow
no further depreciation. See the discussion of reasonable salvage value
in proposed Sec. 1206.112(i)(1)(iii).
1206.162 What are my reporting requirements under an arm's-length
processing contract?
1206.163 What are my reporting requirements under a non-arm's-length
processing contract?
1206.164 What interest or penalties apply if I improperly report a
processing allowance?
1206.165 What reporting adjustments must I make for processing
allowances?
These four proposed sections are the same as the reporting-related
requirements in current 30 CFR 1206.159(c), (d), and (e). Also, they
are the same changes as those discussed above for transportation
allowances under Sec. Sec. 1206.155 through 1206.158.
Subpart F--Federal Coal
1206.250 What is the purpose and scope of this subpart?
This proposed section is the same as current 30 CFR 1206.250, but
we rewrite the current section in Plain Language and make it consistent
with the other product valuation regulations. The substantive
requirements remain unchanged.
1206.251 How do I determine royalty quantity and quality?
This proposed section is the same as current 30 CFR 1206.254,
1206.255, and 1206.260, but we rewrite the sections in Plain Language
and combine multiple sections into this proposed section. We do not
propose any substantive change. However, under proposed paragraph (e),
we clarify the calculation you will have
[[Page 628]]
to perform to allocate washed coal under current 30 CFR 1206.260 by
attributing the washed coal to the leases from which it was extracted.
Thus, proposed new paragraph (e) reads as set forth in the regulatory
text.
1206.252 How do I calculate royalty value for coal I or my affiliate
sell(s) under an arm's-length or non-arm's-length contract?
Current 30 CFR 1206.256 contains valuation standards for Federal
coal leases having cents-per-ton royalty rates. The regulation we
propose eliminates any reference to the valuation of coal from these
leases because there are no longer any Federal cents-per-ton coal
leases. Therefore, this proposed Sec. 1206.252, and the rest of the
proposed regulations, provide lessees with instructions for valuing
coal from ad valorem Federal coal leases.
Consistent with the current Federal coal valuation regulations,
under the proposed regulations, a lessee generally values Federal coal
based on the gross proceeds accruing to the lessee from the first
arm's-length sale. However, like the proposed amendments to the Federal
gas rule we discuss above, we propose to eliminate the benchmarks for
valuation of non-arm's-length sales. We also propose to add the same
``default'' mechanism under Sec. 1206.254 discussed above. Please
refer to proposed Sec. Sec. 1206.141, 1206.142, and 1206.144 above for
an explanation of the proposed changes.
The benchmarks applicable to value coal in non-arm's-length or no-
sale situations have proven difficult to use in practice. In addition,
the first benchmark does not allow the use of comparable arm's-length
sales by the lessee or its affiliates, exacerbating the challenging
process of obtaining and comparing relevant arm's-length sales
contracts to value non-arm's-length sales. Furthermore, disputes arise
over which sales are comparable, particularly because of the inherent
ambiguity in applying the comparability factors.
ONRR is soliciting comments on how to simplify and improve the
valuation of coal disposed of in non-arm's-length transactions and no-
sale situations. We seek input on the merits of eliminating the
benchmarks for valuation of non-arm's-length sales and comments on the
following questions:
Should the royalty value of coal initially sold under non-
arm's-length conditions be based on the gross proceeds received from
the first arm's-length sale of that coal in situations where there is a
subsequent arm's-length sale?
If you are a coal lessee, will adoption of this
methodology substantively impact your current calculation and payment
of royalties on coal and how?
What other methodologies might ONRR use to determine the
royalty value of coal not sold at arm's length that we may not have
considered?
Under proposed paragraph (a), if the lessee sells coal to an
affiliate or another person under a non-arm's-length sales contract,
and the coal purchaser sells the coal under an arm's-length contract,
the lessee must value the coal based on the first arm's-length
contract, less applicable allowances, unless ONRR decides to value the
coal under Sec. 1206.254 (the new ``default'' provision). Please refer
to proposed Sec. 1206.141(b) above for an explanation of the proposed
change.
A lessee that is part of a corporation with affiliates that produce
coal and affiliates that consume the coal in an electrical generation
plant may have transactions to transfer coal without a sale. If the
affiliate consumes the coal to generate electricity, paragraph (a) of
this proposed section would not provide a valuation methodology.
Therefore, ONRR proposes paragraph (b) to explain how a lessee must
value the coal in this circumstance.
Under proposed paragraph (b)(1), if a lessee or its affiliate sells
electricity at arm's length, the royalty value is the sales value of
the electricity, less applicable allowances. In proposed paragraph
(b)(2), if a lessee or its affiliate did not sell electricity at arm's
length, ONRR will determine the royalty value of the coal under the new
``default'' valuation provision in Sec. 1206.254. In this situation, a
lessee must propose a valuation method to ONRR and may use that method
until we issue a determination on the lessee's proposal.
We also propose a new paragraph (c) to explain how to value coal
that a coal cooperative sells. Please refer to Sec. 1206.20 for the
definition of a coal cooperative. A coal cooperative generally operates
as a corporation, with members and owners associated for the purpose of
obtaining a long-term, secure source of coal. This proposed rule will
treat a coal cooperative and its members/owners as affiliated because
they operate without opposing economic interests. Their collective need
is to have a source of coal available to generate electric power and to
be able to purchase that coal at reasonable prices, and, if possible,
below-market prices. The coal cooperative's members are commonly
electric power generation companies, or electric utility, generation,
or transmission cooperatives. The coal cooperative may operate as a
coal lessee, operator, or payor of these and may or may not be
organized to make a profit. Coal cooperatives exist to avoid the
vagaries and potentially higher prices of the free market.
One mechanism that some members of coal cooperatives use to
maintain the lowest possible price for the coal mined and sold to other
members is to refrain from making a profit on such transactions among
members. A coal cooperative can underprice coal even when sales are
arm's length, all other costs being equal. Thus, the proposed
regulations include a new paragraph (c) to value coal sold in these
circumstances.
Under proposed paragraph (c)(1), for sales of coal between the coal
cooperative and coal cooperative members, if the coal is then sold at
arm's-length, we require the lessee to value the coal under paragraph
(a) of this section, regardless of the number of sales between the coal
cooperative members or the coal cooperative and its members. For
example, assume a coal cooperative sold its Federal coal to a coal
cooperative member, and that coal cooperative member sold its coal to
another coal cooperative member who then sold the coal at arm's-length.
In that case, under the proposed rule, the coal would be valued under
paragraph (a) of this section based on the first arm's-length sale.
Under proposed paragraph (c)(2), for sales of coal between the coal
cooperative and coal cooperative members where the coal is consumed in
a power generation plant to generate electricity owned by the coal
cooperative or a coal cooperative member, we require a lessee to value
the coal under proposed paragraph (b) of this section, regardless of
the number of sales between coal cooperative members or between the
coal cooperative and its members. For example, assume a coal
cooperative sold its Federal coal to a coal cooperative member, and
that coal cooperative member sold its coal to another coal cooperative
member who then consumed the coal in its power generation plant and
sold the electricity it generated. In that case, under the proposed
rule, the coal would be valued under paragraph (b) of this section
based on the sales of the electricity, less any allowable deductions.
ONRR believes all sales between cooperative members are non-arm's-
length because they do not have opposing economic interests. However,
we treat sales to non-members of the cooperative like any other arm's-
length
[[Page 629]]
sale under paragraph (a) or paragraph (b) of this section. ONRR seeks
comments on this valuation proposal.
Proposed paragraph (d) states that if you are entitled to take a
washing allowance and transportation allowance for royalty purposes
under this section, the sum of the washing and transportation
allowances may never reduce the royalty value of the coal to zero. This
is the same as current 30 CFR 1206.258(a) and 1206.261(b), but we
rewrite these sections in Plain Language. Unlike the Federal oil and
gas rules, ONRR is not proposing to limit Federal and Indian coal
washing and transportation allowances to 50 percent of the value of the
coal. We specifically request comments as to whether we should limit
coal allowances to 50 percent of the value of the coal.
1206.253 How will ONRR determine if my royalty payments are correct?
1206.254 How will ONRR determine the value of my coal for royalty
purposes?
1206.255 What records must I keep to support my calculations of royalty
under this subpart?
1206.256 What are my responsibilities to place production into
marketable condition and to market production?
1206.257 When is an ONRR audit, review, reconciliation, monitoring, or
other like process considered final?
1206.258 How do I request a valuation determination or guidance?
1206.259 Does ONRR protect information I provide?
ONRR proposes the same changes to Sec. Sec. 1206.253 through
1206.259 as those we propose for Federal gas valuation regulations
under Sec. Sec. 1206.143 through 1206.149. Please refer to those
proposed sections for an explanation of changes.
1206.260 What general transportation allowance requirements apply to
me?
Proposed Sec. 1206.260 retains the provisions in current 30 CFR
1206.261 and makes the Federal coal regulations consistent with the
Federal oil and gas regulations in this proposed rule. This section
also consolidates provisions applicable to both arm's-length and non-
arm's-length transportation in the current regulations, rather than
repeating those provisions in the respective sections for those
allowances. We also rewrite the current regulations in Plain Language
and discuss only substantive changes or additions to this section
below.
Proposed paragraph (a)(1) contains the same provision as current 30
CFR 1206.261(a) allowing you to take a deduction for the reasonable,
actual costs to transport coal from the lease to a point off the lease
or mine determined under Sec. Sec. 1206.261 or 1206.262, as
applicable. We propose a new provision under paragraph (a)(2) to make
clear that you do not need our approval before reporting a
transportation allowance for costs that you incur for arm's-length and
non-arm's-length transportation. This proposal is consistent with
existing practice. Proposed paragraph (b) would contain the remaining
current requirements in 30 CFR 1206.261(a) regarding when you may take
an allowance.
Proposed paragraph (c) explains when you cannot take an allowance.
A new provision in paragraph (c)(1) states that you cannot take an
allowance for transporting lease production that is not royalty
bearing. This new provision is consistent with the existing and
proposed Federal oil and gas regulations. Proposed paragraph (c)(2)
contains the current requirement in 30 CFR 1206.261(a)(2) that you
cannot take an allowance for in-mine movement of your coal. We also
propose a new provision in paragraph (c)(3) that would state you may
not deduct transportation costs to move a particular tonnage of
production for which you did not incur those costs. This codifies our
existing practice of only granting a transportation allowance if you
actually move coal and pay for that movement.
Proposed paragraph (d) is the same as current 30 CFR 1206.261(c)(3)
and permits you to claim a transportation allowance only when you sell
the coal and pay royalties.
We propose to add paragraph (e) to contain and consolidate current
requirements in 30 CFR 1206.261(c)(1), 1206.261(c)(2), and 1206.261(e)
about allocation of transportations costs. This paragraph requires
lessees to report their transportation costs on Form ONRR-4430 as a
cost per ton of clean coal transported. We also explain how to
calculate the cost per ton of clean coal transported.
In addition, we propose to add paragraph (f) to contain the
requirement in current Sec. 1206.262(a)(4) that you must express
arm's-length coal transportation allowances as a dollar-value
equivalent per ton of coal transported. We also make the provision
applicable to non-arm's-length transportation allowances, consistent
with existing practice. Under the proposed regulations, we further
explain that if you do not base your or your affiliate's payments for
transportation under a transportation contract on a dollar-per-unit
basis, you must convert the consideration you or your affiliate paid to
a dollar-value equivalent.
We propose to add paragraph (g), containing the same default
provision as that for the Federal oil and gas transportation
regulations discussed above under Sec. Sec. 1206.110(f) and
1206.152(g), respectively. This proposal includes moving the
requirements of current paragraphs 1206.262(a)(2) and 1206.262(a)(3)
regarding additional consideration, misconduct, and breach of the duty
to market to this new paragraph (g). We also propose to move the
requirements for non-arm's-length transportation allowances to a
separate Sec. 1206.262.
1206.261 How do I determine a transportation allowance if I have an
arm's-length transportation contract or no written arm's-length
contract?
Proposed section 1206.261 explains how lessees must determine
transportation allowances under arm's-length transportation contracts.
These requirements are in current 30 CFR 1206.262(a)(1). However, we
rewrite this section in Plain Language and restructure it for
consistency with the Federal gas transportation allowance regulations
we discuss above in Sec. 1206.153.
We propose to add a new paragraph (c) that would apply if you have
no written contract for the arm's-length transportation of coal. In
that case, ONRR will determine your transportation allowance under
Sec. 1206.254. You must propose to ONRR a method to determine the
allowance using the procedures in Sec. 1206.258(a). You may use that
method to determine your allowance until ONRR issues a determination.
This paragraph does not apply if a lessee performs its own
transportation. Rather, proposed Sec. 1206.262, regarding non-arm's-
length transportation allowances, applies.
1206.262 How do I determine a transportation allowance if I have a non-
arm's-length transportation contract?
ONRR proposes to revise Sec. 1206.262 to explain how lessees must
determine transportation allowances under non-arm's-length
transportation contracts using paragraphs (a) through (k) of this
section. These requirements are in current 30 CFR 1206.262(b). We
rewrite the current requirements in Plain Language and restructure and
amend this section for consistency with the Federal gas transportation
allowance regulations we discuss above in Sec. 1206.154. We also make
several substantive changes discussed below.
[[Page 630]]
The current coal rule at 30 CFR 1206.262(b)(3) provides that a
lessee may request an exception from having to calculate actual costs
for non-arm's-length or no-contract transportation allowances. The
lessee may use the exception if there are Federal- or State-approved
transportation rates. We propose to eliminate the exception for the
following reasons: (1) No lessee has ever applied to use the exception;
(2) the Federal Government no longer sets or approves rail
transportation rates for coal; and (3) the administrative burden on
ONRR to determine approved rates for every State in which coal is
produced is too great.
The current coal rule at 30 CFR 1206.262(b)(2)(iv)(A) permits a
return on undepreciated capital investment in the transportation system
as one of the allowable costs a lessee may include in non-arm's-length
or no-contract transportation allowances. However, under the current
regulation, the return on investment ends after the capital costs are
depreciated to (or below) a reasonable salvage value. In proposed
paragraph (b)(4) of this section, we allow a lessee to continue to take
a return on the reasonable salvage value under paragraph (i) of this
section. Under proposed paragraph (i)(2), after you depreciated a
transportation system to its reasonable salvage value, you may continue
to include in the allowance calculation a cost equal to the reasonable
salvage value, multiplied by the Standard & Poor's BBB rate of return
allowed under paragraph (k) of this section. We propose this change to
make coal valuation regulations consistent with the Federal oil
valuation amendments in proposed Sec. 1206.112(b)(3)(ii) and the
Federal gas valuation amendments in proposed Sec. 1206.154(i)(1)(iii)
(current Federal gas valuation regulation at Sec. 1206.157(g)).
1206.263 What are my reporting requirements under an arm's-length
transportation contract?
1206.264 What are my reporting requirements under a non-arm's-length
transportation contract?
1206.265 What interest and penalties apply if I improperly report a
transportation allowance?
1206.266 What reporting adjustments must I make for transportation
allowances?
ONRR proposes the same revisions to Sec. Sec. 1206.263 through
1206.265 as those we propose for Federal gas valuation regulations
under Sec. Sec. 1206.155 through 1206.157, with two exceptions. ONRR
also proposes to add Sec. 1206.266 to correspond with Sec. 1206.158.
Please refer to those sections for an explanation of the proposed
changes.
The first exception is that these sections keep the same reporting
requirements as current 30 CFR 1206.262(c), 1206.262(d), and
1206.262(e). In addition, proposed Sec. 1206.265 (b)(1) replaces
current 30 CFR 1206.262(d)(1) regarding assessments if you improperly
net a transportation allowance against the sales value of the coal
instead of reporting the allowance as a separate entry on Form ONRR-
4430. Under this proposed regulation, ONRR eliminates assessments
because ONRR is now authorized to assess civil penalties for solid
mineral leases under FOGRMA, 30 U.S.C. 1719 and 30 U.S.C. 1720a.
Penalties are a more effective enforcement mechanism to ensure lessee
compliance with reporting requirements because ONRR can assess civil
penalties that are significantly higher than the maximum assessment the
current regulation authorizes.
1206.267 What general washing allowance requirements apply to me?
ONRR proposes to add this section to contain the requirements of
current 30 CFR 1206.258. This proposal makes the Federal coal valuation
regulations consistent with Federal oil and gas valuations regulations,
and consolidates provisions applicable to both arm's-length and non-
arm's-length washing in the current valuation regulations, rather than
repeating those provisions in the respective sections explaining those
allowances. We also rewrite the current valuation regulations in Plain
Language. We only discuss any substantive changes or additions to this
section below.
Proposed paragraph (a) contains the same information as current 30
CFR 1206.258(a) allowing you to deduct the reasonable, actual costs to
wash coal if you determine the value of your coal under proposed Sec.
1206.252. We also propose a new provision under paragraph (a)(2) to
make clear you do not need ONRR's approval before reporting a washing
allowance for costs that you incur consistent with existing practice.
Proposed paragraph (b) states what you cannot claim when you take a
washing allowance. Paragraph (b)(1) of this section states that you
cannot take an allowance for washing lease production that is not
royalty-bearing. This new provision is consistent with the current and
proposed Federal oil and gas valuation regulations and existing
practices for coal valuation. Paragraph (b)(2) contains the current
prohibition in 30 CFR 1206.258(c) that you cannot disproportionately
allocate washing costs to Federal leases. New paragraph (b)(2) contains
the allocation of washing allowance requirements under current 30 CFR
1206.260. However, new paragraph (b)(2) clarifies how to allocate
washing costs by stating that you must allocate washing costs to washed
coal attributable to each Federal lease by multiplying the input ratio,
which you determine under proposed Sec. 1206.251(e)(2)(i), by the
total allowable costs.
Proposed paragraph (c) contains the requirement of current 30 CFR
1206.259(a)(4) that you must express arm's-length coal washing
allowances as a dollar-value equivalent per ton of coal washed. We also
apply that provision to non-arm's-length washing allowances and make
the section consistent with existing practices. In addition, under this
proposed paragraph, we state that, if you do not base your or your
affiliate's payments for washing under an arm's-length contract on a
dollar-per-unit basis, you have to convert the consideration you or
your affiliate pay to a dollar-value equivalent.
We propose to add a new paragraph (d) containing the same default
provision as that for the Federal oil, gas, and coal transportation
regulations we discuss above under proposed Sec. Sec. 1206.110(f),
1206.152(g), and Sec. 1206.260(g), respectively.
Proposed new paragraph (e) would contain the same provision as
current 30 CFR 1206.258(e) that you may only claim a washing allowance
when you sell the washed coal and report and pay royalties.
1206.268 How do I determine washing allowances if I have an arm's-
length washing contract or no written arm's-length contract?
ONRR proposes to add this section to contain the requirements under
current 30 CFR 1206.259(a)(1), but we rewrite this section in Plain
Language and restructure this section for consistency with the proposed
Federal gas transportation allowance regulations we discussed above in
Sec. 1206.153. This proposal includes moving the requirements of
current Sec. Sec. 1206.259(a)(2) and 1206.259(a)(3) regarding
additional consideration, misconduct, and breach of the duty to market
to the proposed Sec. 1206.267(d) we discussed above. We would move the
requirements for non-arm's-length washing allowances to Sec. 1206.269.
We propose to add a new paragraph (c) that applies if you have no
written contract for the arm's-length washing of coal. In that case,
ONRR may determine
[[Page 631]]
your washing allowance under Sec. 1206.254. You must propose to ONRR a
method to determine the allowance using the procedures in Sec.
1206.258(a). You may use that method to determine your allowance until
ONRR issues a determination. This paragraph would not apply if a lessee
performs its own washing. Rather, Sec. 1206.269 regarding non-arm's-
length washing allowances applies.
1206.269 How do I determine washing allowances if I have a non-arm's-
length washing contract?
ONRR proposes to add new Sec. 1206.269 to explain how lessees must
determine a washing allowance under a non-arm's-length transportation
contract using paragraphs (a) through (k) of this section. These
requirements are in current 30 CFR 1206.259(b). We rewrite the current
requirements in Plain Language and restructure, add, and amend this
section for consistency with the Federal gas and coal transportation
allowance regulations proposed above in Sec. Sec. 1206.154 and
1206.262. We also propose to make several substantive changes we
discuss below.
The current coal rule at 30 CFR 1206.259(b)(2)(iv)(A) permits a
return on undepreciated capital investment in the wash plant as one of
the allowable costs a lessee may include in non-arm's-length or no-
contract transportation allowances. However, under the current
regulation, the return on investment ends after the capital costs are
depreciated to (or below) a reasonable salvage value. In proposed
paragraph (b)(4) of this section, we allow lessees to continue to take
a return on the reasonable salvage value under paragraph (i) of this
section. Under proposed paragraph (i)(2), after you depreciated a wash
plant to its reasonable salvage value, you may continue to include in
the allowance calculation a cost equal to the reasonable salvage value
multiplied by the Standard & Poor's BBB rate of return allowed under
paragraph (k) of this section. We propose this change in order to make
coal valuation regulations consistent with the Federal oil valuation
amendments in proposed Sec. 1206.112(b)(3)(ii) the Federal gas
valuation amendments in proposed Sec. 1206.154(i)(1)(iii) (current
Federal gas valuation regulation at 30 CFR 1206.157(g)), and the
Federal coal valuation regulation amendments proposed in Sec. 1206.262
(b)(4) and in paragraph (i)(2) of this section.
1206.270 What are my reporting requirements under an arm's-length
washing contract?
1206.271 What are my reporting requirements under a non-arm's-length
washing contract?
1206.272 What interest and penalties apply if I improperly report a
washing allowance?
1206.273 What reporting adjustments must I make for washing allowances?
ONRR proposes to add Sec. Sec. 1206.270 through 1206.273, which
are the same as we propose for Federal gas valuation regulations under
Sec. Sec. 1206.155 through 1206.158, with two exceptions. These two
exceptions are the same as we propose in Sec. Sec. 1206.263 through
1206.266. Please refer to those sections for an explanation of the
proposed changes.
Subpart J--Indian Coal
1206.450 What is the purpose and scope of this subpart?
This section would be the same as current 30 CFR 1206.450. We
rewrite the current section in Plain Language and make this section
consistent with the other product valuation regulations. As we
explained above in Sec. 1206.20, we replace the term ``Indian
allottee'' with ``individual Indian mineral owner.'' However, the
substantive requirements remain unchanged.
1206.451 How do I determine royalty quantity and quality?
This proposed section is the same as current 30 CFR 1206.453,
1206.454, and 1206.459, except that we rewrite the sections in Plain
Language and combine multiple current sections into this proposed
section. We are not proposing any substantive change.
1206.452 How do I calculate royalty value for coal I or my affiliate
sell(s) under an arm's-length or non-arm's-length contract?
1206.453 How will ONRR determine if my royalty payments are correct?
1206.454 How will ONRR determine the value of my coal for royalty
purposes?
1206.455 What records must I keep to support my calculations of royalty
under this subpart?
1206.456 What are my responsibilities to place production into
marketable condition and to market production?
1206.457 When is an ONRR audit, review, reconciliation, monitoring, or
other like process considered final?
1206.458 How do I request a valuation determination or guidance?
1206.459 Does ONRR protect information I provide?
ONRR proposes the same changes to Sec. Sec. 1206.452 through
1206.459 as those we proposed for Federal coal valuation regulations
under Sec. Sec. 1206.252 through 1206.259. Please refer to those
proposed sections for an explanation of the changes.
1206.460 What general transportation allowance requirements apply to
me?
We propose the same changes to this section as those we propose for
Federal coal under Sec. 1206.260, with two exceptions. Please refer to
that section for an explanation of the proposed changes.
For Indian coal under current 30 CFR 1206.461(a)(1), a lessee must
submit Form ONRR-4293, Coal Transportation Allowance Report, prior to
taking an allowance. This provision is not in either the current or
proposed Federal coal valuation regulations. However, ONRR proposes to
retain this requirement for coal produced from Indian leases as part of
our trust responsibility. This form submittal ensures that we continue
the oversight and controls necessary on Indian leases.
The current Indian coal regulation at 30 CFR 1206.461(a)(1) also
provide that a lessee who does not timely file Form ONRR-4293 may claim
a transportation allowance retroactively for a period of not more than
3 months prior to the first day of the month that ONRR receives the
lessee's Form ONRR-4293 ``unless ONRR approves a longer period upon a
showing of good cause by the lessee.'' We propose to remove the good
cause exception. We have found this exception is difficult to
administer and is not applicable. See Alexander Energy Corp., 153 IBLA
238 (2000), Union Oil
[[Page 632]]
Company of California, 167 IBLA 263 (2005).
In addition, current 30 CFR 1206.461(c)(1)(vi) provides that ONRR
will allow non-arm's-length contract or no written arm's-length
contract-based transportation allowances in effect at the time these
regulations become effective, to continue until such allowances
terminate. ONRR eliminated this provision for Federal coal leases in
its 1996 Federal coal amendments but left this intact for Indian leases
(61 FR 5481 (1996)). To be consistent, we propose to remove this
provision. ONRR also eliminated this provision for Federal gas leases
(70 FR 11869). Therefore, we propose to add a new paragraph (a)(3)
stating ``You may not use a transportation allowance that was in effect
before the effective date of the final rule. You must use the
provisions of this subpart to determine your transportation
allowance.''
1206.461 How do I determine a transportation allowance if I have an
arm's-length transportation contract or no written arm's-length
contract?
ONRR proposes the same changes to this section as we propose for
Federal coal under Sec. 1206.261. Please refer to that section for an
explanation of the proposed changes.
1206.462 How do I determine a transportation allowance if I have a non-
arm's-length transportation contract?
We propose the same changes to this section as we propose for
Federal coal under Sec. 1206.262, with one exception discussed below.
Please refer to Sec. 1206.262 for an explanation of the proposed
changes.
For Federal coal under proposed Sec. 1206.262, we allow a lessee
to take a return on the reasonable salvage value of a transportation
system. We are not proposing to make this change to Indian coal because
we believe it would reduce the return to the Indian lessor while not
providing a benefit to them. It would therefore not be in the best
interest of the Indian lessor and be inconsistent with our trust
responsibility.
1206.463 What are my reporting requirements under an arm's-length
transportation contract?
We propose to make the same changes to this section as we propose
for Federal coal under Sec. 1206.263 with one exception. Please refer
to Sec. 1206.263 for an explanation of the proposed changes. We also
propose substantive changes to current 30 CFR 1206.461(c) regarding
reporting arm's-length transportation allowances.
Unlike the Federal coal regulation, this proposed Indian coal
regulation would retain the requirement for a lessee to submit Form
ONRR-4293 prior to taking a transportation allowance. These same
provisions are in current 30 CFR 1206.458(c). Form submittal is not a
requirement for Federal leases, but the form submittal ensures we
continue the oversight and controls necessary on Indian leases.
In addition to the changes we make to the reporting requirements
under this section, consistent with the Federal coal valuation
regulations, we propose to eliminate three provisions in the current
Indian coal regulations. First, under the current 30 CFR
1206.461(c)(1)(iii), a lessee may request special reporting procedures
in unique circumstances. ONRR eliminated this provision for Federal
coal leases in its 1996 Federal coal amendments but left it intact for
Indian leases. We do not believe any lessee has ever used this
provision. Therefore, we propose to remove this provision.
Second, the current coal regulation under 30 CFR 1206.461(c)(1)(vi)
states ONRR may establish coal transportation allowance reporting
requirements for individual leases different from those specified in
this subpart to provide more effective administration. ONRR eliminated
this provision for Federal coal leases in its 1996 Federal coal
amendments but left it intact for Indian leases. We do not believe ONRR
has ever used this provision. Therefore, we propose to remove this
provision.
Finally, current 30 CFR 1206.461(c)(1)(vi) provides that ONRR will
allow non-arm's-length contract or no arm's-length contract-based
transportation allowances that are in effect at the time these
regulations become effective to continue until such allowances
terminate. We propose to eliminate this provision and to replace it
with a new Sec. 1206.460(a)(3) we discuss above.
1206.464 What are my reporting requirements under a non-arm's-length
transportation contract?
We propose to make the same amendments to this section as those we
propose for section Sec. Sec. 1206.264 and 1206.463. Please refer to
those proposed sections for an explanation of changes.
1206.465 What interest and penalties apply if I improperly report a
transportation allowance?
We propose to make the same amendments to this section as those we
propose for Sec. 1206.265. Proposed paragraph (b) of this section
prohibits the netting of transportation costs from gross proceeds
received for a particular sale. When eligible to take a transportation
allowance, a lessee must report gross proceeds without a deduction for
transportation costs, and may simultaneously claim a transportation
allowance for the cost of transporting the royalty fraction of Indian
coal sold. Current Indian coal valuation regulations do not contain
this provision. ONRR considers the change to be an enhancement to the
Indian coal regulations that is already in the current Federal coal
valuation regulations at 30 CFR 1206.262(d).
1206.466 What reporting adjustments must I make for transportation
allowances?
We propose the same amendments to this section we propose for Sec.
1206.266. Please refer to the proposed section for an explanation of
the changes.
1206.467 What general washing allowance requirements apply to me?
We propose the same amendments to this section we propose for
Sec. Sec. 1206.267 and 1206.460. However, we propose to maintain the
current requirement that a lessee must submit Form ONRR-4292, Coal
Washing Allowance Report, prior to taking a washing allowance. Please
refer to Sec. Sec. 1206.267 and 1206.460 for an explanation of the
changes.
1206.468 How do I determine a washing allowance if I have an arm's-
length washing contract or no written arm's length contract?
We propose to make the same amendments to this section we propose
for Sec. Sec. 1206.268 and 1206.461. Please refer to Sec. Sec.
1206.268 and 1206.461 for an explanation of the changes.
1206.469 How do I determine a washing allowance if I have a non-arm's-
length washing contract?
We propose to make the same amendments to this section we propose
for Sec. Sec. 1206.269 and 1206.462, with one exception we discuss
below. Please refer to Sec. Sec. 1206.269 and 1206.462 for an
explanation of the changes.
For Federal coal under proposed Sec. 1206.269, we propose to allow
a lessee to continually take a return on the reasonable salvage value
of a wash plant. We do not propose to make this change to Indian coal
because we believe it would reduce the return to the Indian lessor
while not providing a benefit to them. It would therefore not be in the
best interest of the Indian lessor and be inconsistent with our trust
responsibility.
[[Page 633]]
1206.470 What are my reporting requirements under an arm's-length
washing contract?
We propose to make the same amendments to this section we propose
for Sec. Sec. 1206.270 and 1206.463. Please refer to Sec. Sec.
1206.270 and 1206.463 for an explanation of the changes.
1206.471 What are my reporting requirements under a non-arm's-length
washing contract?
We propose to make the same amendments to this section we propose
for Sec. Sec. 1206.271 and 1206.464. Please refer to Sec. Sec.
1206.271 and 1206.464 for an explanation of changes.
1206.472 What interest and penalties apply if I improperly report a
washing allowance?
We propose to make the same amendments to this section we propose
for Sec. Sec. 1206.272 and 1206.465. Please refer to Sec. Sec.
1206.272 and 1206.465 for an explanation of changes.
1206.473 What reporting adjustments must I make for washing allowances?
We propose to make the same amendments to this section we propose
for Sec. Sec. 1206.273 and 1206.466. Please refer to Sec. Sec.
1206.273 and 1206.466 for an explanation of changes.
III. Procedural Matters
1. Summary Cost and Royalty Impact Data
We have summarized estimated costs and benefits the proposed rule
may have on potentially affected groups: Industry, the Federal
Government, Indian lessors, and State and local governments. All of the
proposed amendments that have cost impacts would result in increased
royalty collections. The sum of the proposed amendments that have cost
benefits are due to administrative cost savings to industry, not a
decrease in royalties due. The net impact of the proposed amendments is
an estimated annual increase in royalty collections of between $72.9
million and $87.3 million. This net impact represents a slight increase
of between 0.8 percent and 1.0 percent of the total Federal oil, gas,
and coal royalties ONRR collected in 2010. We also estimate that
industry would experience reduced annual administrative costs of $3.61
million.
Please note that, unless otherwise indicated, numbers in the
following tables are rounded to three significant digits.
A. Industry
The table below lists ONRR's low, mid-range, and high estimates of
the costs, by component, industry would incur in the first year.
Industry would incur these costs in the same amount each year
thereafter.
Summary of Royalty Impacts to Industry
----------------------------------------------------------------------------------------------------------------
Rule provision Low Mid High
----------------------------------------------------------------------------------------------------------------
Gas--replace benchmarks
Affiliate Resale................................... $0 $2,010,000 $4,030,000
Index.............................................. 11,300,000 11,300,000 11,300,000
NGLs--replace benchmarks
Affiliate Resale................................... 0 256,000 510,000
Index.............................................. 1,200,000 1,200,000 1,200,000
Gas transportation limited to 50%...................... 4,170,000 4,170,000 4,170,000
Processing allowance limited to 66\2/3\%............... 5,440,000 5,440,000 5,440,000
POP contracts limited to 66\2/3\% processing allowance. 0 0 0
Extraordinary processing allowance..................... 18,500,000 18,500,000 18,500,000
BBB bond rate change for gas transportation............ 1,640,000 1,640,000 1,640,000
Eliminate deepwater gathering.......................... 17,400,000 20,500,000 23,600,000
Oil Transportation limited to 50%...................... 6,430,000 6,430,000 6,430,000
Oil and gas line losses................................ 4,570,000 4,570,000 4,570,000
Oil line fill.......................................... 978,000 1,710,000 2,450,000
BBB bond rate change for oil transportation............ 2,380,000 2,380,000 2,380,000
Coal--non-arm's length netback & coop sales............ (1,060,000) 0 1,060,000
--------------------------------------------------------
Total.............................................. 72,900,000 80,100,000 87,300,000
----------------------------------------------------------------------------------------------------------------
Note: Totals from this table and others in this analysis may not add due to rounding.
ONRR identified two proposed rule changes that would benefit
industry by reducing their administrative costs. The benefits industry
would realize for each of these components are as follows:
------------------------------------------------------------------------
Rule provision Benefit
------------------------------------------------------------------------
Replace benchmarks--Gas & NGLs....................... $247,000
Eliminate deepwater gathering........................ 3,360,000
------------------
Total............................................ 3,610,000
------------------------------------------------------------------------
The table below lists the overall economic impact to industry from
the proposed changes, based on the mid-range estimate of costs:
------------------------------------------------------------------------
Annual (cost)/
Description benefit amount
------------------------------------------------------------------------
Cost--All Rule Provisions............................ ($80,100,000)
Benefit--Administrative Savings...................... 3,610,000
Net Cost or Benefit to Industry...................... (76,500,000)
------------------------------------------------------------------------
Cost--Using First Arm's-Length Sale To Value Non-Arm's-Length Sales of
Federal Unprocessed Gas, Residue Gas, and Coalbed Methane
As discussed above, we propose replacing the current benchmarks in
30 CFR 1206.152(c) (unprocessed gas) and 1206.152(c) (processed gas)
with a methodology that uses the gross proceeds under the lessee's
affiliate's first arm's-length sale to value gas for royalty purposes.
The lessee also would have the option to elect to pay royalties based
on a value using the monthly high index price, less a standard
deduction for transportation.
To perform this economic analysis, ONRR first extracted royalty
data that we collected on residue gas, unprocessed gas, and coalbed
methane (product codes 03, 04, 39, respectively) for calendar year
2010. We chose calendar year 2010 because the Royalty-in-Kind (RIK)
volumes were minimal due to the 2010 termination of the RIK program. In
previous years, RIK volumes were substantial. Data from RIK production
is not representative of industry sales, so we excluded any
[[Page 634]]
remaining RIK volumes from our analysis. We excluded calendar year 2011
because lessees are still adjusting reports for that year and the data
reported is still going through ONRR's edits.
We then extracted gas royalty data for non-arm's-length
transactions reported with a sales type code of NARM. We also extracted
gas royalty data for sales type code POOL, because royalty reporters
may also use this code to report non-arm's-length transactions. Based
on ONRR's experience auditing transactions that use sales type code
POOL, we know that only a relatively small portion of them are non-
arm's length. Therefore, we used only 10 percent of the POOL volumes in
our economic analysis of the volumes of gas sold non-arm's length.
Based on ONRR's experience auditing production sold under non-
arm's-length contracts, we believe industry would incur a royalty
increase in the range of 0 to 5 cents per MMBtu under our proposal to
use the affiliate's first arm's-length resale to value gas production
for royalty purposes. ONRR created a range of potential royalty
increases by assuming no royalty increase for the low estimate, 2.5
cents per MMBtu for the mid-range estimate, and 5 cents per MMBtu for
the high estimate. We then multiplied the NARM volume and 10 percent of
the POOL volume reported to ONRR in 2010 by the potential royalty
increases.
The results provided below are an estimated cost to industry due to
an annual royalty increase of between zero and approximately $8
million. We reduced this estimate by one-half to $4.03 million,
assuming 50 percent of the non-arm's-length lessees would choose this
option.
----------------------------------------------------------------------------------------------------------------
Royalty increase ($)
2010 MMBtu (non- -----------------------------------------------
rounded) Mid (2.5
Low (0 cents) cents) High (5 cents)
----------------------------------------------------------------------------------------------------------------
NAL Volume.................................... 149,348,561 $0 $3,730,000 $7,470,000
10% of POOL Volume............................ 11,606,523 0 290,000 580,000
-----------------------------------------------------------------
Total..................................... 160,955,084 0 4,020,000 8,050,000
----------------------------------------------------------------------------------------------------------------
50% of lessees choose this option 0 2,010,000 4,030,000
----------------------------------------------------------------------------------------------------------------
Cost--Using Index Price Option To Value Non-Arm's-Length Sales of
Federal Unprocessed Gas, Residue Gas, and Coalbed Methane
To estimate the royalty impact of the index-based option, we
calculated a monthly weighted average price net of transportation using
NARM and 10 percent of the POOL gas royalty data from six major
geographic areas with active index prices--the Green River Basin, San
Juan Basin, Piceance and Uinta Basins, Powder River and Wind River
Basins, Permian Basin, and Offshore Gulf of Mexico (GOM). These six
areas account for approximately 95 percent of all Federal gas produced.
To calculate the estimated impact, we performed the following steps:
(1) Identified the Platts Inside FERC highest reported monthly
price for the index price applicable to each area--Northwest Pipeline
Rockies for Green River, El Paso San Juan for San Juan, Northwest
Pipeline Rockies for Piceance and Uinta, Colorado Interstate Gas for
Powder River and Wind River, El Paso Permian for Permian, and Henry Hub
for GOM.
(2) Subtracted the transportation deduction we specified in the
proposed rule from the highest index price that we identified in step
(1).
(3) Subtracted the average monthly net royalty price reported to us
for unprocessed gas from the highest index price for the same month we
calculated in step (2).
(4) Multiplied the royalty volume by the monthly difference that we
calculated in step (3) to calculate a monthly royalty difference for
each region.
(5) Totaled the difference we calculated in step (4) for the
regions.
Although the index-based methodology resulted in an annual increase
in royalties due, the current average royalty prices reported to us
were higher than the index-based option for 3 months in 2010.
ONRR estimates the cost to industry due to this change would be an
increase in royalty collections of approximately $11.3 million
annually. This estimate represents a small average increase of
approximately 3.6 percent or 14 cents per MMBtu, based on an annual
royalty volume of 160,955,084 MMBtu (for NARM and 10 percent POOL
reported sales type codes). Because this is the first time we have
offered this option, we don't know how many payors will choose it. For
purposes of this analysis, we are assuming that 50 percent of lessees
with non-arm's-length sales would choose this option and, therefore,
have reduced this estimate by one-half. We would like to know from
commenters if this 50-percent assumption is reasonable.
----------------------------------------------------------------------------------------------------------------
2010 Index analysis GOM gas Other gas Total
----------------------------------------------------------------------------------------------------------------
Current Royalties (rounded to the nearest dollar)......... $167,291,148 $435,222,354 $602,513,502
Royalty under Index Option................................ 180,000,000 445,000,000 625,000,000
Difference................................................ 12,700,000 9,780,000 22,500,000
Per Unit Uplift ($/MMBtu)................................. 0.297 0.083 0.140
% change.................................................. 7.06 2.20 3.60
----------------------------------------------------------------------------------------------------------------
50% of lessees choose this option $11,300,000
----------------------------------------------------------------------------------------------------------------
[[Page 635]]
Cost--Using First Arm's-Length Sale To Value Non-Arm's-Length Sales of
Federal NGLs
Like the valuation changes we discussed above, for Federal
unprocessed, residue, and coalbed methane gas valuation changes, the
proposed rule would value processed Federal NGLs based on the first
arm's-length sale rather than the current benchmarks. The lessee would
also have the option to pay royalties using an index price value
derived from an NGL commercial price bulletin less a theoretical
processing allowance that includes transportation and fractionation of
the NGLs. We again used the 2010 NARM and POOL NGL data reported to
ONRR for this analysis.
We performed the same analysis for valuation using the first arm's-
length sale for Federal unprocessed, residue, and coalbed methane gas,
as we discussed above. We identified the non-arm's-length volumes that
would qualify for this option (for NARM and 10 percent POOL reported
sales type codes) and estimated a cents-per-gallon royalty increase.
Based on our experience, we believe that the NGLs resale margin is,
similar to gas, relatively small, ranging from zero to 3 cents per
gallon. Thus, our estimated royalty increase is zero for the low, 1.5
cents per gallon for the mid-range, and 3 cents per gallon for the high
range. The results provided below show a mid-range royalty increase of
$256,000 using these assumptions, and, again, we reduced them by one-
half under the assumption that 50 percent of the lessees would choose
this option. Again, we would ask for comments on the reasonableness of
this 50-percent assumption.
----------------------------------------------------------------------------------------------------------------
2010 Gallons Royalty increase ($)
(rounded to the -----------------------------------------------------
nearest gallon) Low (0 cents) Mid (1.5 cents) High (3 cents)
----------------------------------------------------------------------------------------------------------------
NAL Volume.............................. 6,170,341 $0 $92,600 $185,000
10% of POOL Volume...................... 27,913,486 0 419,000 837,000
-----------------------------------------------------------------------
Total............................... 34,083,827 0 512,000 1,020,000
----------------------------------------------------------------------------------------------------------------
50% of lessees choose this option 0 256,000 510,000
----------------------------------------------------------------------------------------------------------------
Cost--Using Index Price Option To Value Non-Arm's-Length Sales of
Federal NGLs
Like the Federal unprocessed, residue, and coalbed methane gas
changes we discuss above, lessees also would have the option to pay
royalties on Federal NGLs using an index-based value less a theoretical
processing allowance that includes transportation and fractionation. We
used the same 2010 NARM and POOL transaction data for NGLs for this
analysis. We were unable to compare NGLs prices reported on the Form
ONRR-2014 to those in commercial price bulletins because prices lessees
report on the Form ONRR-2014 are one rolled-up price for all NGLs, but
the bulletins price each NGLs product (such as ethane and propane)
separately. Therefore, we base our analysis on the royalty changes that
would result from the theoretical processing allowance proscribed under
this new option.
We chose a conservative number as a proxy for the processing
allowance deduction that we would allow for this index option. To
determine the cost of this option for NGLs, we calculated the
difference between the average processing allowance reported on the
Form ONRR-2014 and the proxy allowance we would allow under this
option. That difference equaled an increase in value of approximately 7
cents per gallon. We then multiplied the total NAL volume of 34,083,827
gallons reported to us by the 7 cents per gallon, for an estimated
royalty increase of $2.4 million. We reduced this number by one-half
under the assumption that 50 percent of lessees would choose this
option, resulting in a total cost to industry of $1.2 million. Again,
we would ask for comments on the reasonableness of this 50-percent
assumption.
Benefit--Using Index Price Option To Value Non-Arm's-Length Federal
Unprocessed Gas, Residue Gas, Coalbed Methane, and NGLs
ONRR expects that industry would benefit by realizing
administrative savings if they choose to use the index-based option to
value non-arm's-length sales of Federal unprocessed gas, residue gas,
coalbed methane, and NGLs. Lessees would know the price to use to value
their production, saving the time it currently takes to calculate the
correct price based on the current benchmarks. They would also save
time using the ONRR-specified transportation rate for gas and the ONRR-
specified processing allowance for NGLs, rather than having to
calculate those values themselves.
Of the lessees that we estimate would use this option, we estimate
the index-based option would shorten the time burden per line reported
by 50 percent to 1.5 minutes for lines industry electronically submits
and 3.5 minutes for lines they manually submit. We used tables from the
Bureau of Labor Statistics (www.bls.gov/oes132011.htm) to estimate the
hourly cost for industry accountants in a metropolitan area. We added a
multiplier of 1.4 for industry benefits. The industry labor cost factor
for accountants would be approximately $50.53 per hour = $36.09 [mean
hourly wage] x 1.4 [benefits cost factor]. Using a labor cost factor of
$50.53 per hour, we estimate the annual administrative benefit to
industry would be approximately $247,000.
----------------------------------------------------------------------------------------------------------------
Estimated lines
Time burden per reported using Annual burden
line reported index option hours
(50%)
----------------------------------------------------------------------------------------------------------------
Electronic Reporting (99%)................................ 1.5 min 190,872 4,772
Manual Reporting (1%)..................................... 3.5 min 1,928 112
----------------------------------------------------------------------------------------------------------------
Industry Labor Cost/hour.................................. ................ ................ $50.53
-----------------
[[Page 636]]
Total Benefit to Industry............................. ................ ................ $247,000
----------------------------------------------------------------------------------------------------------------
Cost--Elimination of Transportation Allowances in Excess of 50 Percent
of the Value of Federal Gas
The current Federal gas valuation regulations limit lessees'
transportation allowances to 50 percent of the value of the gas unless
they request and receive approval to exceed that limit. The proposed
rule would eliminate the lessees' ability to exceed that limit. To
estimate the costs associated with this change, we first identified all
calendar year 2010 reported gas transportation allowances rates that
exceeded the 50-percent limit. We then adjusted those allowances down
to the 50-percent limit and totaled that value to estimate the economic
impact of this provision. The result was an annual estimated cost to
industry of $4.17 million in additional royalties.
Cost--Elimination of Transportation Allowances in Excess of 50 Percent
of the Value of Federal Oil
The current Federal oil valuation regulations limit lessees'
transportation allowances to 50 percent of the value of the oil unless
they request and receive approval to exceed that limit. The proposed
rule would eliminate the lessees' ability to exceed that limit. To
estimate the costs associated with this change, we first identified all
calendar year 2010 reported oil transportation allowance rates that
exceeded the 50-percent limit. We then adjusted those allowances down
to the 50-percent limit and totaled that value to estimate the economic
impact of this provision. The result was an annual estimated cost to
industry of $6.43 million in additional royalties.
Cost--Elimination of Processing Allowances in Excess of 66\2/3\ Percent
of the Value of the NGLs for Federal Gas
The current Federal gas valuation regulations limit lessees'
processing allowances to 66\2/3\ percent of the value of the NGLs
unless they request and receive approval to exceed that limit. The
proposed rule would eliminate the lessees' ability to exceed that
limit. To estimate the cost to industry associated with this change, we
first identified all calendar year 2010 reported processing allowances
greater than 66\2/3\ percent. We then adjusted those allowances down to
the 66\2/3\-percent limit and totaled that value to estimate the
economic impact of this provision. The result was an annual estimated
cost to industry of $5.44 million in additional royalties.
Cost--POP Contracts now Subject to the 66\2/3\ Percent Processing
Allowance Limit for Federal Gas
Lessees with POP contracts currently pay royalties based on their
gross proceeds as long as they pay a minimum value equal to 100 percent
of the residue gas. Under the proposed rule, we also would not allow
lessees with POP contracts to deduct more than the 66\2/3\ percent of
the value of the NGLs. For example, a lessee with a 70-percent POP
contract receives 70 percent of the value of the residue gas and 70
percent of the value of the NGLs. The 30 percent of each product the
lessee gives up to the processing plant in the past could not, when
combined, exceed an equivalent value of 100 percent of the NGLs' value.
Under the proposed rule, the combined value of each product the lessee
gives up to the processing plant cannot exceed two-thirds of the NGLs'
value.
Lessees report POP contracts to ONRR using sales type code APOP for
arm's-length POP contracts and NPOP for non-arm's-length POP contracts.
Because lessees report APOP sales as unprocessed gas, there are no
reported processing allowances for us to analyze and we cannot
determine the breakout between residue gas and NGLs. Lessees do report
residue gas and NGLs separately for NPOPs. However, NPOP volumes
constitute only 0.02 percent of all the natural gas royalty volumes
reported to ONRR. We deemed the NPOP volume to be too low to adequately
assess the impact of this provision on both APOP and NPOP contracts.
Therefore, we decided to examine all reported calendar year 2010
onshore residue gas and NGLs royalty data and assumed it was processed
and that lessees paid royalties as if they sold the residue gas and
NGLs under a POP contract. We restricted our analysis to residue gas
and NGLs volumes produced onshore because we are not aware of any
offshore POP contracts. We first totaled the residue gas and NGLs'
royalty value for calendar year 2010 for all onshore royalties. We then
assumed that these royalties were subject to a 70-percent POP contract.
Based on our experience, a 70/30 split is typical for POP contracts. We
calculated 30 percent of both the value of residue gas and NGLs to
approximate a theoretical 30-percent processing deduction. We then
compared the 30-percent total of residue gas and NGLs values to 66\2/3\
percent of the NGLs value (the maximum allowance under the proposed
rule). The table below summarizes these calculations which we rounded
to the nearest dollar:
----------------------------------------------------------------------------------------------------------------
2010 Royalty
value 70% 30%
----------------------------------------------------------------------------------------------------------------
Residue Gas............................................... $602,194,031 $421,535,822 $180,658,209
NGLs...................................................... 506,818,440 354,772,908 152,045,532
-----------------------------------------------------
Total................................................. 1,109,012,471 776,308,730 332,703,741
----------------------------------------------------------------------------------------------------------------
66.67% Limit.............................................. 337,878,960 (506,818,440 x \2/3\)
----------------------------------------------------------------------------------------------------------------
Our analysis shows that the theoretical processing deduction for 30
percent of the value of residue gas and NGLs ($333 million) under our
assumed onshore POP contract allowance would not exceed the 66\2/3\ cap
($338 million) under the proposed rule and, thus, we estimate that this
change would be revenue neutral.
[[Page 637]]
Cost--Termination of Policy Allowing Transportation Allowances for
Deepwater Gathering Systems for Federal Oil and Gas
The Deep Water Policy we discuss above allows companies to deduct
certain expenses for subsea gathering from their royalty payments, even
though those costs do not meet ONRR's definition of transportation. The
proposed rule would rescind and supersede the Deep Water Policy, and
lessees would have to pay royalties under our proposed valuation
regulations applicable to Federal oil and gas transportation allowances
prospectively. To analyze the cost impact to industry of rescinding
this policy, we used data from BSEE's Arc GIS TIMS (Technical
Information Management System) database to estimate that 113 subsea
pipeline segments serving 108 leases currently qualify for an allowance
under the policy. We assumed all segments were the same--in other
words, we did not take into account the size, length, or type of
pipeline. We also considered only pipeline segments that were in active
status and leases in producing status for our analysis. To determine a
range (shown in the tables below as low, mid, and high estimates) for
the cost to industry, ONRR estimated a 15-percent error rate in our
identification of the 113 eligible pipeline segments, resulting in a
range of 96 to 130 eligible pipeline segments.
Historical ONRR audit data is available for 13 subsea gathering
segments serving 15 leases covering time periods from 1999 through
2010. We used this data to determine an average initial capital
investment in pipeline segments. We used the initial capital investment
amount to calculate depreciation and a return on undepreciated capital
investment (ROI) for the eligible pipeline segments. We calculated
depreciation using a straight-line depreciation schedule based on a 20-
year useful life of the pipeline. We calculated ROI using 1.0 times the
average BBB Bond rate for January 2012, which was the most recent full
month of data when we performed this analysis. We based the
calculations for depreciation and ROI on the first year a pipeline was
in service.
From the same audit data, we calculated an average annual operating
and maintenance (O&M) cost. We increased the O&M cost by 12 percent to
account for overhead expenses. Based on experience and audit data, we
assumed 12 percent is a reasonable increase for overhead. We then
decreased the total annual O&M cost per pipeline segment by 9 percent
because an average of 9 percent of offshore wellhead oil and gas
production is water, which is not royalty bearing. Finally, we used an
average royalty rate of 14 percent, which is the volume weighted
average royalty rate for all non-Section 6 leases in the GOM. Based on
these calculations, the average annual allowance per pipeline segment
is approximately $226,000. This represents the estimated amount per
pipeline segment ONRR will no longer allow a lessee to take as a
transportation allowance based on our rescission of the Deep Water
Policy in this proposed rulemaking.
The total cost to industry would be the $226,000 annual allowance
per pipeline segment that we would disallow under this proposed
rulemaking times the number of eligible segments. To calculate a range
for the total cost, we multiplied the average annual allowance by the
low (96), mid (113), and high (130) number of eligible segments. The
low, mid, and high annual allowance estimates we would disallow are
$21.8 million, $25.6 million, and $29.5 million, respectively.
Of currently eligible leases, 42 out of 108, or about 40 percent,
qualify for deep water royalty relief. However, due to varying lease
terms, royalty relief programs, price thresholds, volume thresholds,
and other factors, ONRR estimated that only half of the 42 leases
eligible for royalty relief (20 percent) actually received royalty
relief. Therefore, we decreased the low, mid, and high estimated annual
cost to industry by 20 percent. The table below shows the estimated
royalty impact of this section of the proposed rule based on the
allowances we would no longer allow under this proposed rule.
----------------------------------------------------------------------------------------------------------------
Low Mid High
----------------------------------------------------------------------------------------------------------------
Estimated Royalty Impact............................... $17,400,000 $20,500,000 $23,600,000
----------------------------------------------------------------------------------------------------------------
Benefit--Termination of Policy Allowing Transportation Allowances for
Deepwater Gathering Systems for Offshore Federal Oil and Gas
ONRR estimates the elimination of transportation allowances for
deepwater gathering systems would provide industry with an
administrative benefit because they would no longer have to perform
this calculation. We believe the cost to perform this calculation is
significant because industry has often hired outside consultants to
calculate their subsea transportation allowances. Using this
information, we estimated each company with leases eligible for
transportation allowances for deepwater gathering systems would
allocate one full-time FTE annually to perform this calculation, if
they use consultants or perform the calculation in-house. We used the
Bureau of Labor Statistics to estimate the hourly cost for industry
accountants in a metropolitan area [$36.09 mean hourly wage] with a
multiplier of 1.4 for industry benefits to equal approximately $50.53
per hour [$36.09 x 1.4]. Using this labor cost per hour, we estimate
the annual administrative benefit to industry would be approximately
$3,360,000.
----------------------------------------------------------------------------------------------------------------
Annual burden Companies Estimated
hours per Industry labor reporting benefit to
company cost/hour eligible leases industry
----------------------------------------------------------------------------------------------------------------
Deepwater Gathering......................... 2,080 $50.53 32 $3,360,000
----------------------------------------------------------------------------------------------------------------
Cost--Elimination of Extraordinary Cost Gas Processing Allowances for
Federal Gas
As we discuss above, we are proposing to eliminate the provision in
our current regulations that allow a lessee to request an extraordinary
processing cost allowance and to terminate any extraordinary cost
processing allowances we previously granted. We have granted two such
approvals in the past, so we know the lease universe that is claiming
this allowance and were able to retrieve the processing allowance data
lessees
[[Page 638]]
deducted from the value of residue gas produced from the leases. We
then calculated the annual total processing allowance lessees have
claimed for 2007 through 2010 for the leases at issue. We then averaged
the yearly totals for those 4 years to estimate an annual cost to
industry of $18.5 million in increased royalties.
Cost--Decrease Rate of Return Used to Calculate Non-Arm's Length
Transportation Allowances from 1.3 to 1 Times the Standard and Poor's
BBB Bond for Federal Oil and Gas
For Federal oil transportation, ONRR does not maintain or request
data identifying if transportation allowances are arm's length or non-
arm's length. However, based on our experience, we believe that a large
portion of GOM oil is transported through lessee-owned pipelines. In
addition, many onshore transportation allowances include costs of
trucking and rail and, most likely, this change would not impact those.
Therefore, to calculate the costs associated with this change, we
assumed that 50 percent of the GOM transportation allowances are non-
arm's length and 10 percent of transportation allowances everywhere
else (onshore and offshore other than the GOM) are non-arm's length. We
also assumed that, over the life of the pipeline, allowance rates are
made up of one-third rate of return on undepreciated capital
investment, one-third depreciation expenses, and one-third operation,
maintenance, and overhead expenses. These are the same assumptions we
made when analyzing changes to both the Federal oil and Federal gas
valuation rules in 2004.
In 2010, the total oil transportation allowances Federal lessees
deducted were approximately $60 million from the GOM and $11 million
from everywhere else. Based on these totals and our assumptions about
the allowance components, the portion of the non-arm's-length
allowances attributable to the rate of return would be approximately
$10,000,000 for the GOM ($60,000,000 x \1/3\ x 50%) and $367,000
($11,000,000 x \1/3\ x 10%) for the rest of the country. Therefore, we
estimate that decreasing the basis for the rate of return by 23 percent
could result in decreased yearly oil transportation allowance
deductions of approximately $2,380,000 ($10,367,000 x 0.23). Thus, we
estimate the net cost to industry as a result of this change would be
an approximately $2,380,000 increase in royalties due.
With respect to Federal gas, like oil, ONRR does not maintain or
request information on whether gas transportation allowances are arm's
length or non-arm's length. However, unlike oil, we believe that it is
not common for GOM gas to be transported through lessee-owned
pipelines. Therefore, we assumed that only 10 percent of all gas
transportation allowances are non-arm's length and made no distinction
between the GOM and everywhere else. All other assumptions for natural
gas are the same as those we made for oil above.
In 2010, the total gas transportation allowances Federal lessees
deducted were approximately $214 million. Based on that total and our
assumptions regarding the makeup of the allowance components, the
portion of the non-arm's-length allowances attributable to the rate of
return would be approximately $7.13 million ($214,000,000 x \1/3\ x
10%). Therefore, we estimate that decreasing the basis for the rate of
return by 23 percent could result in decreased yearly gas
transportation allowance deductions of approximately $1.64 million
($7.13 million x 0.23). That is, the net increased cost to industry,
based on this change, would be approximately $1,640,000 in additional
royalties.
Cost--Allow a Rate of Return on Reasonable Salvage Value for Federal
Oil, Gas, and Coal
For Federal oil and gas, after a transportation system or a
processing plant has been depreciated to its reasonable salvage value,
we propose to allow a lessee a return on that reasonable salvage value
of the transportation system or processing plant as long as the lessee
uses that system or plant for its Federal oil or gas production. We
estimate the economic impact on industry would be small because we
would continue the requirements of the current regulations that a
lessee must base depreciation of a system or plant upon the useful life
of the equipment or the expected life of the reserves served by the
system or plant. Thus, when properly established, the depreciation
schedule should reflect the useful life of the system or plant, and
ONRR would not expect a lessee to continue to use a system or plant for
periods significantly longer than the period reflected by the
depreciation schedule the lessee established for royalty purposes. This
assumption is true especially if the lessee did not make additional
capital expenditures that extended the life of the system or plant. In
that case, the lessee should have extended the depreciation schedule to
reflect the extended life of the system or plant, and, possibly, the
salvage value, itself. In other words, we believe the vast majority of
systems would not be depreciated to salvage value while royalty is
being paid because the system still has a useful life while production
occurs. Thus, we do not believe there would be any costs to industry
associated with this change.
With respect to Federal coal, we believe that the royalty impact
for coal would be equally small for the same reasons we mention above.
Cost--Disallow Line Loss as a Component of Arm's-Length and Non-Arm's-
Length Oil and Gas Transportation
ONRR also proposes to eliminate the current regulatory provision
allowing a lessee to deduct costs of pipeline losses, both actual and
theoretical, when calculating non-arm's-length transportation
allowances. For this analysis, we assumed that pipeline losses are 0.2
percent of the volume transported through the pipeline, based on a
survey of pipeline tariff. This 0.2 percent of the volume transported
also equates to 0.2 percent of the value of the Federal royalty volume
of oil and gas production transported.
For Federal oil produced in calendar year 2010, the total value of
the Federal royalty volume subject to transportation allowances was
$3,796,827,823 in the GOM and $1,204,177,633 everywhere else. Using our
previous assumption that 50 percent of GOM and 10 percent of everywhere
else's transportation allowances are non-arm's length, we estimated
that the value of the line loss would be $4.04 million, as we detailed
in the table below. Therefore, the annual cost to industry would be
approximately $4.04 million in additional royalties.
[[Page 639]]
Oil Line Loss Royalty Impact
----------------------------------------------------------------------------------------------------------------
Line loss (%) Royalty increase
----------------------------------------------------------------------------------------------------------------
50% of GOM royalty value............................ $1,898,413,912 0.2 $3,800,000
10% of everywhere else royalty value................ 120,417,763 0.2 241,000
-----------------------------------------------------------
Total........................................... .................. .................. 4,040,000
----------------------------------------------------------------------------------------------------------------
For Federal gas produced in calendar year 2010, the royalty value
of the Federal gas royalty volume subject to transportation allowances
was $2,656,843,158. Using our previous assumption that 10 percent of
Federal gas transportation allowances are non-arm's length, we
estimated the value of the line loss would be $530,000. Therefore, the
annual cost to industry would be approximately $530,000 in increased
royalties.
Gas Line Loss Royalty Impact
----------------------------------------------------------------------------------------------------------------
Line loss (%) Royalty increase
----------------------------------------------------------------------------------------------------------------
10% of royalty value................................ $265,684,316 0.2 $531,000
----------------------------------------------------------------------------------------------------------------
The total estimated royalty increase for both oil and gas due to
this change would be $4.57 million [$4,040,000 (oil) plus $531,000
(gas) = $4,570,000].
Cost--Disallow Line Fill as a Component of Non-Arm's-Length Oil
Transportation Allowances
We estimated that oil line fill costs ranged from a low $0.02 to a
high of $0.05 per barrel, with a mid-range of $0.035. These are the
same estimates we made in our 2004 oil valuation rule when we made a
change to allow this component as a cost of oil transportation, and we
believe these cost estimates are still valid. We restricted our
analysis to only oil production from the GOM because we believe that
including line fill as a component of transportation allowances is
uncommon everywhere else. We then applied these estimates to the total
2010 GOM Federal oil royalty volume of 48,910,000 barrels to estimate
the range of reduced transportation costs included in allowance
calculations, as we detail in the table below.
Line Fill Royalty Impact Estimate
----------------------------------------------------------------------------------------------------------------
Low Mid High
-----------------------------------------------------------
2010 Federal GOM Royalty Oil Volume (barrels) ($0.035 per
($0.02 per barrel) barrel) ($0.05 per barrel)
----------------------------------------------------------------------------------------------------------------
48,910,000.......................................... $978,000 $1,710,000 $2,450,000
----------------------------------------------------------------------------------------------------------------
In other words, based on this analysis, the proposed rule would not
allow lessees to include the amounts in the table above as a component
of their transportation allowance.
Cost--Depreciating Oil Pipeline Assets Only Once
ONRR proposes to allow depreciation of oil pipeline assets only one
time. Under our current valuation regulations for Federal oil, if an
oil pipeline is sold, ONRR allows the purchasing company to include the
purchase price to establish a new depreciation schedule and, in
essence, depreciate the same piece of pipe twice or more if it is sold
again. Under this proposed rulemaking, we would allow depreciation only
once. In theory, this change could result in additional royalties.
However, based on our experience monitoring the oil markets, we believe
that the sale of oil pipeline assets is rare, and we are not aware of
any such sales in the last 5 calendar years. We are also not aware of
any planned future sales of oil pipelines that this proposed rule
change would impact. Therefore, although ONRR believes that there will
be a cost to industry under this proposal, we cannot quantify the cost
at this time.
Cost--Using First Arm's-Length Sale To Value Non-Arm's-Length Sales of
Federal Coal and Sales of Federal Coal Between Coal Cooperatives and
Coal Cooperative Members and Between Coal Cooperative Members
We discuss this cost in the next section.
Cost--Using Sales of Electricity To Value Non-Arm's-Length Sales of
Federal Coal and Sales of Federal Coal Between Coal Cooperatives and
Coal Cooperative Members and Between Coal Cooperative Members
In ONRR's experience, non-arm's-length sales of Federal coal that
is then resold at arm's length are rare. Under the current valuation
regulations, such sales result in royalty values equivalent to values
that result under the proposed regulation at Sec. 1206.252(a) based on
arm's-length resale prices. Thus, ONRR estimates that there will be no
royalty effect for these types of sales. In other words, there is no
cost to lessees who produce Federal coal due to this valuation change
in the proposed rule.
The remaining non-arm's-length dispositions of Federal coal
(including lessees, their affiliates, coal cooperatives, and members of
coal cooperatives) are when the lessee, its affiliate, coal
cooperatives, or members of coal cooperatives consume(s) the Federal
coal produced to generate electricity. These dispositions typically
constitute from about one to two percent of royalties paid on Federal
coal produced.
Under the proposed rule, a lessee, its affiliates, a coal
cooperative, and a member of a coal cooperative generally would base
the royalty value of such sales on the sales value of the electricity,
less costs to generate and, in some cases, transmit the electricity to
the buyers, and less applicable coal washing and transportation costs.
ONRR has limited experience determining lease product royalty values
using the
[[Page 640]]
methodology under proposed Sec. 1206.252(b)(1). Therefore, to perform
an economic analysis, ONRR first determined the average royalties paid
to ONRR in calendar years 2009 through 2011 for these Federal coal
dispositions. Based on our experience with other dispositions of
Federal coal, ONRR estimated that, at most, royalty values under the
proposed rule would increase or decrease by 10 percent, compared to
royalty values we determined under current regulations. Using these
assumptions, ONRR estimated the annual average royalty impact and,
thus, the cost or benefit to industry from the proposed rule.
Our methodology is the same for estimating the royalty impact of
using sales of electricity to value non-arm's-length sales of Federal
coal, sales of Federal coal between coal cooperatives and coal
cooperative members, and sales between coal cooperative members.
Therefore, the estimated royalty impact would be a combined figure
covering all such valuation of Federal coal under the proposed rule.
Accordingly, ONRR estimates the combined average annual royalty impacts
for these coal dispositions would range from a royalty decrease of
$1.06 million (benefit) to a royalty increase of $1.06 million (cost).
ONRR requests comments on its estimates of the cost regarding
valuation of these dispositions of Federal coal under the proposed
rule. In particular, we seek information on the costs of electric power
generation and transmission and whether the proposed rule would result
in royalty increases or decreases.
Cost--Using Default Provision To Value Non-Arm's-Length Sales of
Federal Coal in Lieu of Sales of Electricity
If ONRR were unable to establish royalty values of Federal coal
using the sales value of electricity generated from coal produced,
royalty value would be based on a method the lessee proposes under
Sec. 1206.252(b)(2)(i), which ONRR approves, or on a method that ONRR
determines under Sec. 1206.254. In either case, ONRR would accept or
would assign a royalty value that would approximate the market value of
the coal. Whether valuing under Sec. Sec. 1206.252(b)(2)(i) or
1206.254, the lessee and ONRR would employ a valuation method that uses
or approximates market value. Current coal valuation regulations also
attempt to provide royalty values that would approximate the market
value of this coal. Thus, given the low percentage of non-arm's-length
dispositions of Federal coal and the use of market-based methods to
determine royalty value under the current regulations and the proposed
rule, if valuation does not follow Sec. 1206.252(a) or Sec.
1206.252(b)(1), ONRR estimates that the royalty effect of the proposed
rule on lessees of Federal coal would be nominal.
Cost--Using First Arm's-Length Sale To Value Non-Arm's-Length Sales of
Indian Coal
Currently, lessees of Indian coal sell their entire production at
arm's-length so this proposed change would have no cost impact on
lessees of Indian coal.
Cost--Using Sales of Electricity To Value Non-Arm's-Length Sales of
Indian Coal
Currently, lessees of Indian coal sell their entire production at
arm's-length so this proposed change would have no cost impact on
lessees of Indian coal.
Cost--Using First Arm's-Length Sale To Value Sales of Indian Coal
Between Coal Cooperative Members
Currently, no coal cooperatives are lessees of Indian coal, so we
do not expect there to be any royalty impact as a result of the
proposed rule change.
Cost--DOI Use of Default Provision To Value Federal Oil, Gas, or Coal
and Indian Coal
As we discussed above, we propose to add a ``default provision''
that addresses valuation when the Secretary cannot determine the value
of production because of a variety of factors, or the Secretary
determined the value is wrong for a multitude of reasons (for example,
misconduct). In those cases, the Secretary would exercise his/her
authority, and considerable discretion, to establish the reasonable
value of production using a variety of discretionary factors and any
other information the Secretary believes is appropriate. This default
provision covers all products (Federal oil, gas and coal, and Indian
coal) and all pertinent valuation factors (sales, transportation,
processing, and washing).
Based on our experience, ONRR believes it would rarely use the
default option. We also believe that assigning a royalty impact figure
to any of the default provisions is speculative because (1) each
instance would be case-specific, (2) we cannot anticipate when we would
use the option, and (3) we cannot anticipate the value we would require
companies to pay. Additionally, we believe the royalty impact would be
relatively small because the default provisions would always establish
a reasonable value of production using market-based transaction data,
which has always been the basis for our royalty valuation rules in the
first instance.
B. State and Local Governments
This proposed rule would not impose any additional burden on local
governments. ONRR estimates that the States this rule impacts would
receive an overall increase in royalties as follows:
States receiving revenues for offshore Outer Continental Shelf
Lands Act Section 8(g) leases would share in a portion of the increased
royalties resulting from this proposed rule, as would States receiving
revenues from onshore Federal lands. Based on the ratio of Federal
revenues disbursed to States for section 8(g) leases and onshore States
we detail in the table below, ONRR assumed the same proportion of
revenue increases for each proposal that would impact those State
revenues for most of the provisions.
Royalty Distributions by Lease Type
------------------------------------------------------------------------
Onshore Offshore 8(g)
(%) (%) (%)
------------------------------------------------------------------------
Fed......................................... 50 100 73
State....................................... 50 0 0
State (8g).................................. 0 0 27
------------------------------------------------------------------------
Some provisions, such as deepwater gathering allowances, affect
only Federal revenues, while others, such as the extraordinary
processing allowance, affect only onshore States and Federal revenues.
The table summarizing the State and local government royalty increases
we provide in section E details these differences.
The State distribution for offshore royalties would increase at
some point in time because of the provisions of the Gulf of Mexico
Energy Security Act of 2006 (GOMESA) (Pub. Law No. 109-432, 120 Stat.
2922). Section 105 of GOMESA provides Outer Continental Shelf (OCS) oil
and gas revenue sharing provisions for the four Gulf producing States
(Alabama, Louisiana, Mississippi, and Texas) and their eligible coastal
political subdivisions. Through fiscal year 2016, the only shareable
qualified revenues originate from leases issued within two small
geographic areas. Beginning in fiscal year 2017, qualified revenues
originating from leases issued since the passing of GOMESA located
within the balance of the GOM acreage will also become shareable. The
majority of these leases are not yet producing. The time necessary to
start production operations and to produce royalty-bearing quantities
varies from
[[Page 641]]
lease to lease, and these factors directly influence how the
distribution of offshore royalties will change over time. None of the
leases in these frontier areas have begun producing, and we believe it
is speculative to anticipate when they will begin producing royalty-
bearing quantities and impact the distribution of revenues to States.
C. Indian Lessors
ONRR estimates that the proposed changes to the coal regulations
that apply to Indian lessors would have no impact on their royalties.
D. Federal Government
The impact to the Federal Government, like the States, would be a
net overall increase in royalties as a result of these proposed
changes. In fact, the royalty increase anticipated by the Federal
Government would be the difference between the total royalty increase
from industry and the royalty increase affecting the States. The net
yearly impact on the Federal Government would be approximately $61.8
million we detail in section E.
E. Summary of Royalty Impacts and Costs to Industry, State and Local
Governments, Indian Lessors, and the Federal Government.
In the table below, the negative values in the Industry column
represent their estimated royalty increases, while the positive values
in the other columns represent the increase in royalty receipts by each
affected group. For purposes of this summary table, we assumed that the
average for royalty increases is the midpoint of our range.
----------------------------------------------------------------------------------------------------------------
Rule provision Industry Federal State State 8(g)
----------------------------------------------------------------------------------------------------------------
Gas--replace benchmarks
Affiliate Resale............................ ($2,010,000) $1,390,000 $605,000 $13,500
Index....................................... (11,300,000) 7,820,000 3,400,000 75,700
NGLs--replace benchmarks
Affiliate Resale............................ (256,000) 191,000 63,000 1,850
Index....................................... (1,200,000) 896,000 295,000 8,650
Gas transportation limited to 50%............... (4,170,000) 2,890,000 1,260,000 27,900
Processing allowance limited to 66\2/3\ %....... (5,440,000) 4,060,000 1,340,000 39,200
POP contracts limited to 66\2/3\ %.............. 0 0 0 0
Extraordinary processing allowance.............. (18,500,000) 9,250,000 9,250,000 0
BBB bond rate change for gas transportation..... (1,640,000) 1,140,000 494,000 11,000
Eliminate deepwater gathering................... (20,500,000) 20,500,000 0 0
Oil Transportation limited to 50%............... (6,430,000) 5,810,000 594,000 27,100
Oil and gas line losses......................... (4,570,000) 4,130,000 422,000 19,200
Oil line fill................................... (1,710,000) 1,540,000 158,000 7,190
BBB bond rate change for oil transportation..... (2,380,000) 2,150,000 220,000 10,000
Coal--non-arm's length netback & coop sales..... 0 0 0 0
---------------------------------------------------------------
Total....................................... (80,100,000) 61,800,000 18,100,000 241,000
----------------------------------------------------------------------------------------------------------------
2. Regulatory Planning and Review (E.O. 12866)
This document is a significant rule, and the Office of Management
and Budget (OMB) has reviewed this proposed rule under Executive Order
12866. We made the assessments that E.O. 12866 requires, and we provide
the results below.
a. This proposed rule would not have an effect of $100 million or
more on the economy. It would not adversely affect in a material way
the economy, productivity, competition, jobs, the environment, public
health or safety, or state, local, or tribal governments or
communities. The Summary of Royalty Impacts table, in item 1 above,
demonstrates that the economic impact on industry, State and local
governments, and the Federal Government would be well below the $100
million threshold the Federal Government uses to define a rule as
having a significant impact on the economy.
b. This proposed rule would not create a serious inconsistency or
otherwise interfere with an action another agency has taken or planned.
ONRR is the only agency that promulgates rules for royalty valuation on
Federal oil and gas leases and Federal and Indian coal leases.
c. This proposed rule would not alter the budgetary effects of
entitlements, grants, user fees, or loan programs or the rights or
obligations of their recipients. The scope of this proposed rule does
not have a material impact in any of these areas.
d. This proposed rule would raise novel legal or policy issues but
would simplify the valuation regulations, thus reducing the possibility
of impacts as a result of any novel legal and policy issues.
3. Regulatory Flexibility Act
The Department of the Interior certifies that this proposed rule
would not have a significant economic effect on a substantial number of
small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et
seq.); see item 1 above for analysis.
4. Small Business Regulatory Enforcement Fairness Act
This proposed rule is not a major rule under 5 U.S.C. 804(2), the
Small Business Regulatory Enforcement Fairness Act. This proposed rule:
a. Would not have an annual effect on the economy of $100 million
or more. We estimate the maximum effect would be $87,300,000. See item
1 above.
b. Would not cause a major increase in costs or prices for
consumers, individual industries, Federal, State, or local government
agencies, or geographic regions. See item 1 above.
c. Would not have significant adverse effects on competition,
employment, investment, productivity, innovation, or the ability of
U.S.-based enterprises to compete with foreign-based enterprises. This
proposed rule would be to the benefit of U.S.-based enterprises and
would be a result of suggestions made through the Royalty Policy
Committee made up, in part, of industry representatives.
5. Unfunded Mandates Reform Act
This proposed rule would not impose an unfunded mandate on state,
local, or tribal governments, or the private sector of more than $100
million per year. This proposed rule would not have a significant or
unique effect on State, local, or tribal governments, or the private
sector. Therefore, we are not providing a statement containing the
information that the Unfunded
[[Page 642]]
Mandates Reform Act (2 U.S.C. 1501 et seq.) requires. See item 1 above.
6. Takings Implication Assessment (E.O. 12630)
Under the criteria in E.O. 12630, this proposed rule would not have
significant takings implications. This proposed rule would apply to
Federal oil, Federal gas, Federal coal, and Indian coal leases only.
This proposed rule would not be a governmental action capable of
interference with constitutionally protected property rights. This
proposed rule does not require a Takings Implication Assessment.
7. Federalism (E.O. 13132)
Under the criteria in E.O. 13132, this proposed rule would not have
sufficient federalism implications to warrant the preparation of a
Federalism Assessment. The management of Federal oil leases, Federal
gas leases, and Federal and Indian coal leases is the responsibility of
the Secretary of the Interior. This proposed rule would not impose
administrative costs on States or local governments. Therefore, this
proposed rule would not require a Federalism Assessment.
8. Civil Justice Reform (E.O. 12988)
This proposed rule would comply with the requirements of E.O.
12988, for the reasons we outline in the following paragraphs.
The proposed rule would meet the criteria of section 3(a), which
requires that we write and review all regulations to eliminate errors
and ambiguity in order to minimize litigation.
The proposed rule would meet the criteria of section 3(b)(2), which
requires that we write all regulations in clear language with clear
legal standards.
9. Consultation with Indian Tribes (E.O. 13175)
Under the criteria in E.O. 13175, we evaluated this proposed rule
and determined it would have potential effects on federally recognized
Indian tribes. Specifically, this rule would change the valuation
methodology for coal produced from Indian leases as discussed above.
Accordingly:
(a) We consulted with the affected tribes on a government-to-
government basis.
(b) We will fully consider tribal views in the final rule.
10. Paperwork Reduction Act
This proposed rule also refers to, but does not change, the
information collection requirements that OMB already approved under OMB
Control Numbers 1012-0004, 1012-0005, and 1012-0010. Since the proposed
rule is reorganizing our current regulations, please refer to the
Derivations Table in Section III for specifics. The corresponding
information collection burden tables will be updated during their
normal renewal cycle. See 5 CFR 1320.4(a)(2).
11. National Environmental Policy Act
This proposed rule would not constitute a major Federal action
significantly affecting the quality of the human environment. A
detailed statement under the National Environmental Policy Act of 1969
(NEPA) is not required because this rule is categorically excluded
under: ``(i) Policies, directives, regulations, and guidelines: that
are of an administrative, financial, legal, technical, or procedural
nature.'' See 43 CFR 46.210(i) and the DOI Departmental Manual, part
516, section 15.4.D. We also have determined that this rule is not
involved in any of the extraordinary circumstances listed in 43 CFR
46.215 that would require further analysis under NEPA. The procedural
changes resulting from these amendments would have no consequences with
respect to the physical environment. This proposed rule would not alter
in any material way natural resource exploration, production, or
transportation.
12. Data Quality Act
In developing this proposed rule, we did not conduct or use a
study, experiment, or survey requiring peer review under the Data
Quality Act (Pub. L. 106-554), also known as the Information Quality
Act. The Department of the Interior has issued guidance regarding the
quality of information that it relies on for regulatory decisions. This
guidance is available on DOI's Web site at www.doi.gov/ocio/iq.html.
13. Effects on the Energy Supply (E.O. 13211)
This proposed rule would not be a significant energy action under
the definition in E.O. 13211, and, therefore, would not require a
Statement of Energy Effects.
14. Clarity of this Regulation
Executive Orders 12866 and 12988 and the Presidential Memorandum of
June 1, 1998, require us to write all rules in Plain Language. This
means that each rule that we publish must: (a) Have logical
organization; (b) use the active voice to address readers directly; (c)
use clear language rather than jargon; (d) use short sections and
sentences; and (e) use lists and tables wherever possible.
If you feel that we have not met these requirements, send your
comments to [email protected]. To better help us revise the
rule, make your comments as specific as possible. For example, you
should tell us the numbers of the sections or paragraphs that you think
we wrote unclearly, which sections or sentences are too long, the
sections where you feel lists or tables would be useful, etc.
15. Public Availability of Comments
Before including your address, phone number, email address, or
other personal identifying information in your comment, you should be
aware that your entire comment--including your personal identifying
information--may be made publicly available at any time. While you can
ask us, in your comment, to withhold your personal identifying
information from public view, we cannot guarantee that we will be able
to do so.
List of Subjects in 30 CFR Parts 1202 and 1206
Coal, Continental shelf, Government contracts, Indian lands,
Mineral royalties, Natural gas, Petroleum, Public lands--mineral
resources, Reporting and recordkeeping requirements.
Dated: December 18, 2014.
Kris Sarri,
Principal Deputy Assistant Secretary for Policy, Management and Budget.
Authority and Issuance
For the reasons stated in the preamble, the Office of Natural
Resources Revenue proposes to amend 30 CFR parts 1202 and 1206 as set
forth below:
PART 1202--ROYALTIES
0
1. The authority citation for part 1202 continues to read as follows:
Authority: 5 U.S.C. 301 et seq., 25 U.S.C. 396 et seq., 396a et
seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et
seq.,1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.,1331 et
seq., and 1801 et seq.
Subpart B--Oil, Gas, and OCS Sulfur, General
0
2. In Sec. 1202.51,revise paragraph (b) to read as follows:
Sec. 1202.51 Scope and definitions.
* * * * *
(b) The d[eacute]finitions in Sec. 1206.20 of this chapter are
applicable to subparts B, C, D, and J of this part.
[[Page 643]]
Subpart F--Coal
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3. Add Sec. 1202.251 to subpart F to read as follows:
Sec. 1202.251 What coal is subject to royalties?
(a) All coal (except coal unavoidably lost as determined by BLM
under 43 CFR part 3400) from a Federal or Indian lease is subject to
royalty. This includes coal used, sold, or otherwise disposed of by you
on or off the lease.
(b) If you receive compensation for unavoidably lost coal through
insurance coverage or other arrangements, you must pay royalties at the
rate specified in the lease on the amount of compensation you receive
for the coal. No royalty is due on insurance compensation you received
for other losses.
(c) If you rework waste piles or slurry ponds to recover coal, you
must pay royalty at the rate specified in the lease at the time you
use, sell, or otherwise finally dispose of the recovered coal.
(1) The applicable royalty rate depends on the production method
you used to initially mine the coal contained in the waste pile or
slurry pond (i.e., underground mining method or surface mining method).
(2) You must allocate coal in waste pits or slurry ponds you
initially mined from Federal or Indian leases to those Federal or
Indian leases regardless of whether it is stored on Federal or Indian
lands.
(3)You must maintain accurate records demonstrating how to allocate
the coal in the waste pit or slurry pond to each individual Federal or
Indian coal lease.
PART 1206--PRODUCT VALUATION
0
4. The authority citation for part 1206 continues to read as follows:
Authority: 5 U.S.C. 301 et seq., 25 U.S.C. 396 et seq., 396a et
seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et
seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et
seq., and 1801 et seq.
0
5. Revise subpart A to read as follows:
Subpart A--General Provisions and Definitions
Sec.
1206.10 Has the Office of Management and Budget (OMB) approved the
information collection requirements in this part?
1206.20 What definitions apply to this part?
Subpart A--General Provisions
Sec. 1206.10 Has the Office of Management and Budget (OMB) approved
the information collection requirements in this part?
OMB has approved the information collection requirement contained
in this part under 44 U.S.C. 3501 et seq. See 30 CFR part 1210 for
details concerning the estimated reporting burden and how to comment on
the accuracy of the burden estimate.
Sec. 1206.20 What definitions apply to this part?
Ad valorem lease means a lease where the royalty due to the lessor
is based upon a percentage of the amount or value of the coal.
Affiliate means a person who controls, is controlled by, or is
under common control with another person. For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the
voting securities, or instruments of ownership, or other forms of
ownership, of another person constitutes control. Ownership of less
than 10 percent constitutes a presumption of noncontrol that ONRR may
rebut.
(2) If there is ownership or common ownership of 10 through 50
percent of the voting securities or instruments of ownership, or other
forms of ownership, of another person, ONRR will consider the following
factors to determine if there is control under the circumstances of a
particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of
ownership, or other forms of ownership: the percentage of ownership or
common ownership, the relative percentage of ownership or common
ownership compared to the percentage(s) of ownership by other persons,
if a person is the greatest single owner, or if there is an opposing
voting bloc of greater ownership;
(iii) Operation of a lease, plant, pipeline, or other facility;
(iv) The extent of participation by other owners in operations and
day-to-day management of a lease, plant, or other facility; and
(v) Other evidence of power to exercise control over or common
control with another person.
(3) Regardless of any percentage of ownership or common ownership,
relatives, either by blood or marriage, are affiliates.
ANS means Alaska North Slope (ANS).
Area means a geographic region at least as large as the limits of
an oil and/or gas field, in which oil and/or gas lease products have
similar quality and economic characteristics. Area boundaries are not
officially designated and the areas are not necessarily named.
Arm's-length contract means a contract or agreement between
independent persons who are not affiliates and who have opposing
economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this
definition for that month, as well as when the contract was executed.
Audit means an examination, conducted under the generally accepted
Governmental Auditing Standards, of royalty reporting and payment
compliance activities of lessees, designees or other persons who pay
royalties, rents, or bonuses on Federal leases or Indian leases.
BIA means the Bureau of Indian Affairs, Department of the Interior.
BLM means the Bureau of Land Management, Department of the
Interior.
BOEM means the Bureau of Ocean Energy Management, Department of the
Interior.
BSEE means the Bureau of Safety and Environmental Enforcement,
Department of the Interior.
Coal means coal of all ranks from lignite through anthracite.
Coal cooperative means an entity organized to provide coal or coal-
related services to the entity's members (who may also be owners of the
entity), partners, and others. The entity's members are commonly
electric power generation companies, electric utilities, and electric
generation and transmission cooperatives. The entity may operate as a
coal lessee, operator, payor, or affiliate of these, and may or may not
be organized to make a profit.
Coal washing means any treatment to remove impurities from coal.
Coal washing may include, but is not limited to, operations such as
flotation, air, water, or heavy media separation; drying; and related
handling (or combination thereof).
Compression means the process of raising the pressure of gas.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees
of API gravity) recovered at the surface without processing. Condensate
is the mixture of liquid hydrocarbons resulting from condensation of
petroleum hydrocarbons existing initially in a gaseous phase in an
underground reservoir.
Constraint means a reduction in, or elimination of, gas flow,
deliveries or sales required by the delivery system.
Contract means any oral or written agreement, including amendments
or revisions, between two or more persons, that is enforceable by law
and that with due consideration creates an obligation.
[[Page 644]]
Designee means the person the lessee designates to report and pay
the lessee's royalties for a lease.
Exchange agreement means an agreement where one person agrees to
deliver oil to another person at a specified location in exchange for
oil deliveries at another location. Exchange agreements may or may not
specify prices for the oil involved. They frequently specify dollar
amounts reflecting location, quality, or other differentials. Exchange
agreements include buy/sell agreements, which specify prices to be paid
at each exchange point and may appear to be two separate sales within
the same agreement. Examples of other types of exchange agreements
include, but are not limited to, exchanges of produced oil for specific
types of crude oil (e.g., West Texas Intermediate); exchanges of
produced oil for other crude oil at other locations (Location Trades);
exchanges of produced oil for other grades of oil (Grade Trades); and
multi-party exchanges.
FERC means Federal Energy Regulatory Commission.
Field means a geographic region situated over one or more
subsurface oil and gas reservoirs and encompassing at least the
outermost boundaries of all oil and gas accumulations known within
those reservoirs, vertically projected to the land surface. State oil
and gas regulatory agencies usually name onshore fields and designate
their official boundaries. BOEM names and designates boundaries of OCS
fields.
Gas means any fluid, either combustible or noncombustible,
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and
which has neither independent shape nor volume, but tends to expand
indefinitely. It is a substance that exists in a gaseous or rarefied
state under standard temperature and pressure conditions.
Gas plant products means separate marketable elements, compounds,
or mixtures, whether in liquid, gaseous, or solid form, resulting from
processing gas, excluding residue gas.
Gathering means the movement of lease production to a central
accumulation or treatment point on the lease, unit, or communitized
area, or to a central accumulation or treatment point off the lease,
unit, or communitized area that BLM or BSEE approves for onshore and
offshore leases, respectively, including any movement of bulk
production from the wellhead to a platform offshore.
Geographic region means, for Federal gas, an area at least as large
as the defined limits of an oil and or gas field in which oil and/or
gas lease products have similar quality and economic characteristics.
Gross proceeds means the total monies and other consideration
accruing for the disposition of any of the following:
(1) Oil. Gross proceeds also include, but are not limited to, the
following examples:
(i) Payments for services such as dehydration, marketing,
measurement, or gathering which the lessee must perform at no cost to
the Federal Government;
(ii) The value of services, such as salt water disposal, that the
producer normally performs but that the buyer performs on the
producer's behalf;
(iii) Reimbursements for harboring or terminalling fees, royalties,
and any other reimbursements;
(iv) Tax reimbursements, even though the Federal royalty interest
may be exempt from taxation;
(v) Payments made to reduce or buy down the purchase price of oil
produced in later periods, by allocating such payments over the
production whose price the payment reduces and including the allocated
amounts as proceeds for the production as it occurs; and
(vi) Monies and all other consideration to which a seller is
contractually or legally entitled but does not seek to collect through
reasonable efforts;
(2) Gas, residue gas, and gas plant products. Gross proceeds also
include, but are not limited to, the following examples:
(i) Payments for services such as dehydration, marketing,
measurement, or gathering that the lessee must perform at no cost to
the Federal Government;
(ii) Reimbursements for royalties, fees, and any other
reimbursements;
(iii) Tax reimbursements, even though the Federal royalty interest
may be exempt from taxation; and
(iv) Monies and all other consideration to which a seller is
contractually or legally entitled, but does not seek to collect through
reasonable efforts; or
(3) Coal. Gross proceeds also include, but are not limited to, the
following examples:
(i) Payments for services such as crushing, sizing, screening,
storing, mixing, loading, treatment with substances including chemicals
or oil, and other preparation of the coal that the lessee must perform
at no cost to the Federal Government or Indian lessor;
(ii) Reimbursements for royalties, fees, and any other
reimbursements;
(iii) Tax reimbursements even though the Federal or Indian royalty
interest may be exempt from taxation; and
(iv) Monies and all other consideration to which a seller is
contractually or legally entitled, but does not seek to collect through
reasonable efforts.
Index means:
(1) For gas, the calculated composite price ($/MMBtu) of spot
market sales a publication that meets ONRR-established criteria for
acceptability at the index pricing point publishes; or
(2) For oil, the calculated composite price ($/barrel) of spot
market sales a publication that meets ONRR-established criteria for
acceptability at the index pricing point publishes.
Index pricing point means any point on a pipeline for which there
is an index, which ONRR-approved publications may refer to as a trading
location.
Index zone means a field or an area with an active spot market and
published indices applicable to that field or an area that is
acceptable to ONRR under Sec. 1206.141(d)(1).
Indian Tribe means any Indian Tribe, band, nation, pueblo,
community, rancheria, colony, or other group of Indians for which any
minerals or interest in minerals is held in trust by the United States
or that is subject to Federal restriction against alienation.
Individual Indian mineral owner means any Indian for whom minerals
or an interest in minerals is held in trust by the United States or who
holds title subject to Federal restriction against alienation.
Keepwhole contract means a processing agreement under which the
processor delivers to the lessee a quantity of gas after processing
equivalent to the quantity of gas the processor received from the
lessee prior to processing, normally based on heat content, less gas
used as plant fuel and gas unaccounted for and/or lost. This includes
but is not limited to agreements under which the processor retains all
NGLs it recovered from the lessee's gas.
Lease means any contract, profit-sharing arrangement, joint
venture, or other agreement issued or approved by the United States
under any mineral leasing law, including the Indian Mineral Development
Act, 25 U.S.C. 2101-2108, that authorizes exploration for, extraction
of, or removal of lease products, or the geographical area covered by
that authorization, whichever is required by the context.
Lease products mean any leased minerals, attributable to,
originating
[[Page 645]]
from, or allocated to a lease or produced in association with a lease.
Lessee means any person to whom the United States, an Indian tribe,
and/or individual Indian mineral owner issues a lease, and any person
who has been assigned all or a part of record title, operating rights,
or an obligation to make royalty or other payments required by the
lease. This includes:
(1) Any person who has an interest in a lease; and
(2) In the case of leases for Indian coal or Federal coal, an
operator, payor, or other person with no lease interest who makes
royalty payments on the lessee's behalf.
Like quality means similar chemical and physical characteristics.
Location differential means an amount paid or received (whether in
money or in barrels of oil) under an exchange agreement that results
from differences in location between oil delivered in exchange and oil
received in the exchange. A location differential may represent all or
part of the difference between the price received for oil delivered and
the price paid for oil received under a buy/sell exchange agreement.
Market center means a major point ONRR recognizes for oil sales,
refining, or transshipment. Market centers generally are locations
where ONRR-approved publications publish oil spot prices.
Marketable condition means lease products which are sufficiently
free from impurities and otherwise in a condition that they will be
accepted by a purchaser under a sales contract typical for the field or
area for Federal oil and gas, and region for Federal and Indian coal.
Mine means an underground or surface excavation or series of
excavations and the surface or underground support facilities that
contribute directly or indirectly to mining, production, preparation,
and handling of lease products.
Misconduct means any failure to perform a duty owed to the United
States under a statute, regulation, or lease, or unlawful or improper
behavior, regardless of the mental state of the lessee or any
individual employed by or associated with the lessee.
Net output means the quantity of:
(1) Residue gas and each gas plant product that a processing plant
produces; or
(2) The quantity of washed coal that a coal wash plant produces.
Netting means reducing the reported sales value to account for an
allowance instead of reporting the allowance as a separate entry on
Form ONRR-2014 or Form ONRR-4430.
NGLs means natural gas liquids.
NYMEX price means the average of the New York Mercantile Exchange
(NYMEX) settlement prices for light sweet crude oil delivered at
Cushing, Oklahoma, calculated as follows:
(1) Sum the prices published for each day during the calendar month
of production (excluding weekends and holidays) for oil to be delivered
in the prompt month corresponding to each such day; and
(2) Divide the sum by the number of days on which those prices are
published (excluding weekends and holidays).
Oil means a mixture of hydrocarbons that existed in the liquid
phase in natural underground reservoirs, remains liquid at atmospheric
pressure after passing through surface separating facilities, and is
marketed or used as a liquid. Condensate recovered in lease separators
or field facilities is oil.
ONRR means the Office of Natural Resources Revenue, Department of
the Interior.
ONRR-approved commercial price bulletin means a publication ONRR
approves for determining NGLs prices.
ONRR-approved publication means:
(1) For oil, a publication ONRR approves for determining ANS spot
prices or WTI differentials; or
(2) For gas, a publication ONRR approves for determining index
pricing points.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of lands beneath navigable waters as
defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of
which the subsoil and seabed appertain to the United States and are
subject to its jurisdiction and control.
Payor means any person who reports and pays royalties under a
lease, regardless of whether that person also is a lessee.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Processing means any process designed to remove elements or
compounds (hydrocarbon and nonhydrocarbon) from gas, including
absorption, adsorption, or refrigeration. Field processes which
normally take place on or near the lease, such as natural pressure
reduction, mechanical separation, heating, cooling, dehydration, and
compression, are not considered processing. The changing of pressures
and/or temperatures in a reservoir is not considered processing. The
use of a Joules-Thompson (JT) unit to remove NGLs from gas is
considered processing regardless of where the JT unit is located
provided that you market the NGLs as NGLs.
Processing allowance means a deduction in determining royalty value
for the reasonable, actual costs the lessee incurs for processing gas.
Prompt month means the nearest month of delivery for which NYMEX
futures prices are published during the trading month.
Quality differential means an amount paid or received under an
exchange agreement (whether in money or in barrels of oil) that results
from differences in API gravity, sulfur content, viscosity, metals
content, and other quality factors between oil delivered and oil
received in the exchange. A quality differential may represent all or
part of the difference between the price received for oil delivered and
the price paid for oil received under a buy/sell agreement.
Region for coal means the eight Federal coal production regions,
which the Bureau of Land Management designates as follows: Denver-Raton
Mesa Region, Fort Union Region, Green River-Hams Fork Region, Powder
River Region, San Juan River Region, Southern Appalachian Region,
Uinta-Southwestern Utah Region, and Western Interior Region. See 44 FR
65197 (1979).
Residue gas means that hydrocarbon gas consisting principally of
methane resulting from processing gas.
Rocky Mountain Region means the States of Colorado, Montana, North
Dakota, South Dakota, Utah, and Wyoming, except for those portions of
the San Juan Basin and other oil-producing fields in the ``Four
Corners'' area that lie within Colorado and Utah.
Roll means an adjustment to the NYMEX price that is calculated as
follows: Roll = .6667 x (P0-P1) + .3333 x
(P0-P2), where: P0 = the average of
the daily NYMEX settlement prices for deliveries during the prompt
month that is the same as the month of production, as published for
each day during the trading month for which the month of production is
the prompt month; P1 = the average of the daily NYMEX
settlement prices for deliveries during the month following the month
of production, published for each day during the trading month for
which the month of production is the prompt month; and P2 =
the average of the daily NYMEX settlement prices for deliveries during
the second month following the month of production, as published for
each day during the trading month for which the month of production is
the prompt month. Calculate the average of
[[Page 646]]
the daily NYMEX settlement prices using only the days on which such
prices are published (excluding weekends and holidays).
(1) Example 1. Prices in Out Months are Lower Going Forward:
The month of production for which you must determine royalty value
is December. December was the prompt month (for year 2011) from
October 21 through November 18. January was the first month
following the month of production, and February was the second month
following the month of production. P0 therefore is the
average of the daily NYMEX settlement prices for deliveries during
December published for each business day between October 21 and
November 18. P1 is the average of the daily NYMEX
settlement prices for deliveries during January published for each
business day between October 21 and November 18. P2 is
the average of the daily NYMEX settlement prices for deliveries
during February published for each business day between October 21
and November 18. In this example, assume that P0 = $95.08
per bbl, P1 = $95.03 per bbl, and P2 = $94.93
per bbl. In this example (a declining market), Roll = .6667 x
($95.08-$95.03) + .3333 x ($95.08-$94.93) = $0.03 + $0.05 = $0.08.
You add this number to the NYMEX price.
(2) Example 2. Prices in Out Months are Higher Going Forward:
The month of production for which you must determine royalty value
is November. November was the prompt month (for year 2012) from
September 21 through October 22. December was the first month
following the month of production, and January was the second month
following the month of production. P0 therefore is the
average of the daily NYMEX settlement prices for deliveries during
November published for each business day between September 21 and
October 22. P1 is the average of the daily NYMEX
settlement prices for deliveries during December published for each
business day between September 21 and October 22. P2 is
the average of the daily NYMEX settlement prices for deliveries
during January published for each business day between September 21
and October 22. In this example, assume that P0 = $91.28
per bbl, P1 = $91.65 per bbl, and P2 = $92.10
per bbl. In this example (a rising market), Roll = .6667 x ($91.28-
$91.65) + .3333 x ($91.28-$92.10) = (-$0.25) + (-$0.27) = (-$0.52).
You add this negative number to the NYMEX price (effectively a
subtraction from the NYMEX price).
Sale means a contract between two persons where:
(1) The seller unconditionally transfers title to the oil, gas, gas
plant product, or coal to the buyer and does not retain any related
rights such as the right to buy back similar quantities of oil, gas,
gas plant product, or coal from the buyer elsewhere;
(2) The buyer pays money or other consideration for the oil, gas,
gas plant product, or coal; and
(3) The parties' intent is for a sale of the oil, gas, gas plant
product, or coal to occur.
Section 6 lease means an OCS lease subject to section 6 of the
Outer Continental Shelf Lands Act, as amended, 43 U.S.C. 1335.
Short tons means 2000 pounds.
Spot price means the price under a spot sales contract where:
(1) A seller agrees to sell to a buyer a specified amount of oil at
a specified price over a specified period of short duration;
(2) No cancellation notice is required to terminate the sales
agreement; and
(3) There is no obligation or implied intent to continue to sell in
subsequent periods.
Tonnage means tons of coal measured in short tons.
Trading month means the period extending from the second business
day before the 25th day of the second calendar month preceding the
delivery month (or, if the 25th day of that month is a non-business
day, the second business day before the last business day preceding the
25th day of that month) through the third business day before the 25th
day of the calendar month preceding the delivery month (or, if the 25th
day of that month is a non-business day, the third business day before
the last business day preceding the 25th day of that month), unless the
NYMEX publishes a different definition or different dates on its
official Web site, www.nymex.com, in which case the NYMEX definition
will apply.
Transportation allowance means a deduction in determining royalty
value for the reasonable, actual costs the lessee incurs for moving:
(1) Oil to a point of sale or delivery off the lease, unit area, or
communitized area. The transportation allowance does not include
gathering costs; or
(2) Unprocessed gas, residue gas, or gas plant products to a point
of sale or delivery off the lease, unit area, or communitized area, or
away from a processing plant. The transportation allowance does not
include gathering costs; or
(3) Coal to a point of sale remote from both the lease and mine or
wash plant.
Washing allowance means a deduction in determining royalty value
for the reasonable, actual costs the lessee incurs for coal washing.
WTI differential means the average of the daily mean differentials
for location and quality between a grade of crude oil at a market
center and West Texas Intermediate (WTI) crude oil at Cushing published
for each day for which price publications perform surveys for
deliveries during the production month, calculated over the number of
days on which those differentials are published (excluding weekends and
holidays). Calculate the daily mean differentials by averaging the
daily high and low differentials for the month in the selected
publication. Use only the days and corresponding differentials for
which such differentials are published.
0
6. Revise subpart C to read as follows:
Subpart C--Federal Oil
Sec.
1206.100 What is the purpose of this subpart?
1206.101 How do I calculate royalty value for oil I or my affiliate
sell(s) under an arm's-length contract?
1206.102 How do I value oil that is not sold under an arm's-length
contract?
1206.103 What publications does ONRR approve?
1206.104 How will ONRR determine if my royalty payments are correct?
1206.105 How will ONRR determine the value of my oil for royalty
purposes?
1206.106 What records must I keep to support my calculations of
value under this subpart?
1206.107 What are my responsibilities to place production into
marketable condition and to market production?
1206.108 How do I request a value determination?
1206.109 Does ONRR protect information I provide?
1206.110 What general transportation allowance requirements apply to
me?
1206.111 How do I determine a transportation allowance if I have an
arm's-length transportation contract?
1206.112 How do I determine a transportation allowance if I do not
have an arm's-length transportation contract?
1206.113 What adjustments and transportation allowances apply when I
value oil production from my lease using NYMEX prices or ANS spot
prices?
1206.114 How will ONRR identify market centers?
1206.115 What are my reporting requirements under an arm's-length
transportation contract?
1206.116 What are my reporting requirements under a non-arm's-length
transportation contract?
1206.117 What interest and penalties apply if I improperly report a
transportation allowance?
1206.118 What reporting adjustments must I make for transportation
allowances?
1206.119 How do I determine royalty quantity and quality?
Subpart C--Federal Oil
Sec. 1206.100 What is the purpose of this subpart?
(a) This subpart applies to all oil produced from Federal oil and
gas leases onshore and on the OCS. It explains how you as a lessee must
calculate the value of production for
[[Page 647]]
royalty purposes consistent with mineral leasing laws, other applicable
laws, and lease terms.
(b) If you are a designee and if you dispose of production on
behalf of a lessee, the terms ``you'' and ``your'' in this subpart
refer to you and not to the lessee. In this circumstance, you must
determine and report royalty value for the lessee's oil by applying the
rules in this subpart to your disposition of the lessee's oil.
(c) If you are a designee and only report for a lessee and do not
dispose of the lessee's production, references to ``you'' and ``your''
in this subpart refer to the lessee and not the designee. In this
circumstance, you as a designee must determine and report royalty value
for the lessee's oil by applying the rules in this subpart to the
lessee's disposition of its oil.
(d) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee
resulting from administrative or judicial litigation;
(3) A written agreement between the lessee and the ONRR Director
establishing a method to determine the value of production from any
lease that ONRR expects at least would approximate the value
established under this subpart; or
(4) An express provision of an oil and gas lease subject to this
subpart, then the statute, settlement agreement, written agreement, or
lease provision will govern to the extent of the inconsistency.
(e) ONRR may audit, monitor, or review and adjust all royalty
payments.
Sec. 1206.101 How do I calculate royalty value for oil I or my
affiliate sell(s) under an arm's-length contract?
(a) The value of oil under this section for royalty purposes is the
gross proceeds accruing to you or your affiliate under the arm's-length
contract less applicable allowances determined under Sec. 1206.111 or
Sec. 1206.112. This value does not apply if you exercise an option to
use a different value provided in paragraph (c)(1) or (c)(2)(i) of this
section or if ONRR decides to value your oil under Sec. 1206.105. You
must use this paragraph (a) to value oil when:
(1) You sell under an arm's-length sales contract; or
(2) You sell or transfer to your affiliate or another person under
a non-arm's-length contract and that affiliate or person, or another
affiliate of either of them, then sells the oil under an arm's-length
contract, unless you exercise the option provided in paragraph
(c)(2)(i) of this section.
(b) If you have multiple arm's-length contracts to sell oil
produced from a lease that is valued under paragraph (a) of this
section, the value of the oil is the volume-weighted average of the
values established under this section for each contract for the sale of
oil produced from that lease.
(c)(1) If you enter into an arm's-length exchange agreement, or
multiple sequential arm's-length exchange agreements, and following the
exchange(s) you or your affiliate sell(s) the oil received in the
exchange(s) under an arm's-length contract, then you may use either
Sec. 1206.101(a) or Sec. 1206.102 to value your production for
royalty purposes. If you fail to make the election required under this
paragraph, you may not make a retroactive election and ONRR may decide
your value under Sec. 1206.105.
(i) If you use Sec. 1206.101(a), your gross proceeds are the gross
proceeds under your or your affiliate's arm's-length sales contract
after the exchange(s) occur(s). You must adjust your gross proceeds for
any location or quality differential, or other adjustments, you
received or paid under the arm's-length exchange agreement(s). If ONRR
determines that any arm's-length exchange agreement does not reflect
reasonable location or quality differentials, ONRR may decide your
value under Sec. 1206.105. You may not otherwise use the price or
differential specified in an arm's-length exchange agreement to value
your production.
(ii) When you elect under Sec. 1206.101(c)(1) to use Sec.
1206.101(a) or Sec. 1206.102, you must make the same election for all
of your production from the same unit, communitization agreement, or
lease (if the lease is not part of a unit or communitization agreement)
sold under arm's-length contracts following arm's-length exchange
agreements. You may not change your election more often than once every
2 years.
(2)(i) If you sell or transfer your oil production to your
affiliate and that affiliate or another affiliate then sells the oil
under an arm's-length contract, you may use either Sec. 1206.101(a) or
Sec. 1206.102 to value your production for royalty purposes.
(ii) When you elect under Sec. 1206.101(c)(2)(i) to use Sec.
1206.101(a) or Sec. 1206.102, you must make the same election for all
of your production from the same unit, communitization agreement, or
lease (if the lease is not part of a unit or communitization agreement)
that your affiliates resell at arm's-length. You may not change your
election more often than once every 2 years.
Sec. 1206.102 How do I value oil not sold under an arm's-length
contract?
This section explains how to value oil that you may not value under
Sec. 1206.101 or that you elect under Sec. 1206.101(c)(1) to value
under this section, unless ONRR decides to value your oil under
1206.105. First, determine if paragraph (a), (b), or (c) of this
section applies to production from your lease, or if you may apply
paragraph (d) or (e) with ONRR approval.
(a) Production from leases in California or Alaska. Value is the
average of the daily mean ANS spot prices published in any ONRR-
approved publication during the trading month most concurrent with the
production month. For example, if the production month is June,
calculate the average of the daily mean prices using the daily ANS spot
prices published in the ONRR-approved publication for all the business
days in June.
(1) To calculate the daily mean spot price, you must average the
daily high and low prices for the month in the selected publication.
(2) You must use only the days and corresponding spot prices for
which such prices are published.
(3) You must adjust the value for applicable location and quality
differentials, and you may adjust it for transportation costs, under
Sec. 1206.111.
(4) After you select an ONRR-approved publication, you may not
select a different publication more often than once every 2 years,
unless the publication you use is no longer published or ONRR revokes
its approval of the publication. If you must change publications, you
must begin a new 2-year period.
(b) Production from leases in the Rocky Mountain Region. This
paragraph provides methods and options for valuing your production
under different factual situations. You must consistently apply
paragraph (b)(2) or (3) of this section to value all of your production
from the same unit, communitization agreement, or lease (if the lease
or a portion of the lease is not part of a unit or communitization
agreement) that you cannot value under Sec. 1206.101 or that you elect
under Sec. 1206.101(c)(1) to value under this section.
(1) You may elect to value your oil under either paragraph (b)(2)
or (3) of this section. After you select either paragraph (b)(2) or (3)
of this section, you may not change to the other method more often than
once every 2 years, unless the method you have been using is no longer
applicable and you must apply the other paragraph. If you change
[[Page 648]]
methods, you must begin a new 2-year period.
(2) Value is the volume-weighted average of the gross proceeds
accruing to the seller under your or your affiliate's arm's-length
contracts for the purchase or sale of production from the field or area
during the production month.
(i) The total volume purchased or sold under those contracts must
exceed 50 percent of your and your affiliate's production from both
Federal and non-Federal leases in the same field or area during that
month.
(ii) Before calculating the volume-weighted average, you must
normalize the quality of the oil in your or your affiliate's arm's-
length purchases or sales to the same gravity as that of the oil
produced from the lease.
(3) Value is the NYMEX price (without the roll), adjusted for
applicable location and quality differentials and transportation costs
under Sec. 1206.113.
(4) If you demonstrate to ONRR's satisfaction that paragraphs
(b)(2) through (3) of this section result in an unreasonable value for
your production as a result of circumstances regarding that production,
the ONRR Director may establish an alternative valuation method.
(c) Production from leases not located in California, Alaska, or
the Rocky Mountain Region. (1) Value is the NYMEX price, plus the roll,
adjusted for applicable location and quality differentials and
transportation costs under Sec. 1206.113.
(2) If the ONRR Director determines that use of the roll no longer
reflects prevailing industry practice in crude oil sales contracts or
that the most common formula used by industry to calculate the roll
changes, ONRR may terminate or modify use of the roll under paragraph
(c)(1) of this section at the end of each 2-year period [EFFECTIVE DATE
OF THE FINAL RULE], through notice published in the Federal Register
not later than 60 days before the end of the 2-year period. ONRR will
explain the rationale for terminating or modifying the use of the roll
in this notice.
(d) Unreasonable value. If ONRR determines that the NYMEX price or
ANS spot price does not represent a reasonable royalty value in any
particular case, ONRR may decide to value your oil under Sec.
1206.105.
(e) Production delivered to your refinery and the NYMEX price or
ANS spot price is an unreasonable value. If ONRR determines that the
NYMEX price or ANS spot price does not represent a reasonable royalty
value in any particular case, ONRR may decide to value under Sec.
1206.105.
Sec. 1206.103 What publications does ONRR approve?
(a) ONRR periodically will publish to www.onrr.gov a list of ONRR-
approved publications for the NYMEX price and ANS spot price based on
certain criteria including, but not limited to:
(1) Publications buyers and sellers frequently use;
(2) Publications frequently mentioned in purchase or sales
contracts;
(3) Publications that use adequate survey techniques, including
development of estimates based on daily surveys of buyers and sellers
of crude oil, and, for ANS spot prices, buyers and sellers of ANS crude
oil; and
(4) Publications independent from ONRR, other lessors, and lessees.
(b) Any publication may petition ONRR to be added to the list of
acceptable publications.
(c) ONRR will specify the tables you must use in the acceptable
publications.
(d) ONRR may revoke its approval of a particular publication if it
determines that the prices or differentials published in the
publication do not accurately represent NYMEX prices or differentials
or ANS spot market prices or differentials.
Sec. 1206.104 How will ONRR determine if my royalty payments are
correct?
(a)(1) ONRR may monitor, review, and audit the royalties you
report, and, if ONRR determines that your reported value is
inconsistent with the requirements of this subpart, ONRR may direct you
to use a different measure of royalty value or decide your value under
Sec. 1206.105.
(2) If ONRR directs you to use a different royalty value, you must
either pay any additional royalties due, plus late payment interest
calculated under Sec. Sec. 1218.54 and 1218.102 of this chapter) or
report a credit for, or request a refund of, any overpaid royalties.
(b) When the provisions in this subpart refer to gross proceeds, in
conducting reviews and audits, ONRR will examine if your or your
affiliate's contract reflects the total consideration actually
transferred, either directly or indirectly, from the buyer to you or
your affiliate for the oil. If ONRR determines that a contract does not
reflect the total consideration, ONRR may decide your value under Sec.
1206.105.
(c) ONRR may decide your value under Sec. 1206.105 if ONRR
determines that the gross proceeds accruing to you or your affiliate
under a contract do not reflect reasonable consideration because:
(1) There is misconduct by or between the contracting parties;
(2) You have breached your duty to market the oil for the mutual
benefit of yourself and the lessor by selling your oil at a value that
is unreasonably low. ONRR may consider a sales price to be unreasonably
low if it is 10 percent less than the lowest reasonable measures of
market price, including but not limited to, index prices and prices
reported to ONRR for like quality oil; or
(3) ONRR cannot determine if you properly valued your oil under
Sec. 1206.101 or Sec. 1206.102 for any reason, including but not
limited to, you or your affiliate's failure to provide documents ONRR
requests under 30 CFR part 1212, subpart B.
(d) You have the burden of demonstrating that your or your
affiliate's contract is arm's-length.
(e) ONRR may require you to certify that the provisions in your or
your affiliate's contract include all of the consideration the buyer
paid you or your affiliate, either directly or indirectly, for the oil.
(f)(1) Absent contract revision or amendment, if you or your
affiliate fail(s) to take proper or timely action to receive prices or
benefits to which you or your affiliate are entitled, you must pay
royalty based upon that obtainable price or benefit.
(2) If you or your affiliate make timely application for a price
increase or benefit allowed under your or your affiliate's contract but
the purchaser refuses and you or your affiliate take reasonable
documented measures to force purchaser compliance, you will not owe
additional royalties unless or until you or your affiliate receive
additional monies or consideration resulting from the price increase.
You may not construe this paragraph to permit you to avoid your royalty
payment obligation in situations where a purchaser fails to pay, in
whole or in part, or timely, for a quantity of oil.
(g)(1) You or your affiliate must make all contracts, contract
revisions, or amendments in writing and all parties to the contract
must sign the contract, contract revisions, or amendments.
(2) If you or your affiliate fail(s) to comply with paragraph
(g)(1) of this section, ONRR may determine your value under Sec.
1206.105.
(3) This provision applies notwithstanding any other provisions in
this title 30 to the contrary.
Sec. 1206.105 How will ONRR determine the value of my oil for royalty
purposes?
If ONRR decides that it will value your oil for royalty purposes
under Sec. 1206.104, or any other provision in
[[Page 649]]
this subpart, then ONRR will determine value, for royalty purposes, by
considering any information we deem relevant, which may include, but is
not limited to:
(a) The value of like-quality oil in the same field or nearby
fields or areas;
(b) The value of like-quality oil from the refinery or area;
(c) Public sources of price or market information that ONRR deems
reliable;
(d) Information available and reported to ONRR, including but not
limited to, on Form ONRR-2014 and Form ONRR-4054;
(e) Costs of transportation or processing if ONRR determines they
are applicable; or
(f) Any information ONRR deems relevant regarding the particular
lease operation or the salability of the oil.
Sec. 1206.106 What records must I keep to support my calculations of
value under this subpart?
If you determine the value of your oil under this subpart, you must
retain all data relevant to the determination of royalty value.
(a) You must show:
(1) How you calculated the value you reported, including all
adjustments for location, quality, and transportation; and
(2) How you complied with these rules.
(b) You can find recordkeeping requirements in parts 1207 and 1212
of this chapter.
(c) ONRR may review and audit your data, and ONRR will direct you
to use a different value if it determines that the reported value is
inconsistent with the requirements of this subpart.
Sec. 1206.107 What are my responsibilities to place production into
marketable condition and to market production?
(a) You must place oil in marketable condition and market the oil
for the mutual benefit of the lessee and the lessor at no cost to the
Federal Government.
(b) If you use gross proceeds under an arm's-length contract in
determining value, you must increase those gross proceeds to the extent
that the purchaser, or any other person, provides certain services that
the seller normally would be responsible to perform to place the oil in
marketable condition or to market the oil.
Sec. 1206.108 How do I request a value determination?
(a) You may request a value determination from ONRR regarding any
oil produced. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, all interest owners
of those leases, the designee(s), and the operator(s) for those leases;
(3) Completely explain all relevant facts. You must inform ONRR of
any changes to relevant facts that occur before we respond to your
request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to
all relevant precedents (including adverse precedents); and
(6) Suggest your proposed valuation method.
(b) In response to your request, ONRR may:
(1) Request that the Assistant Secretary for Policy, Management and
Budget issue a valuation determination;
(2) Decide that ONRR will issue guidance; or
(3) Inform you in writing that ONRR will not provide a
determination or guidance. Situations in which ONRR typically will not
provide any determination or guidance include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or
administrative appeals.
(c)(1) A value determination the Assistant Secretary for Policy,
Management and Budget signs is binding on both you and ONRR until the
Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a value determination, you
must make any adjustments to royalty payments that follow from the
determination and, if you owe additional royalties, you must pay the
additional royalties due, plus late payment interest calculated under
Sec. Sec. 1218.54 and 1218.102 of this chapter.
(3) A value determination the Assistant Secretary signs is the
final action of the Department and is subject to judicial review under
5 U.S.C. 701-706.
(d) Guidance ONRR issues is not binding on ONRR, delegated States,
or you with respect to the specific situation addressed in the
guidance.
(1) Guidance and ONRR's decision whether or not to issue guidance
or request an Assistant Secretary determination, or neither, under
paragraph (b) of this section, are not appealable decisions or orders
under 30 CFR part 1290.
(2) If you receive an order requiring you to pay royalty on the
same basis as the guidance, you may appeal that order under 30 CFR part
1290.
(e) ONRR or the Assistant Secretary may use any of the applicable
valuation criteria in this subpart to provide guidance or make a
determination.
(f) A change in an applicable statute or regulation on which ONRR
or the Assistant Secretary based any determination or guidance takes
precedence over the determination or guidance, regardless of whether
ONRR or the Assistant Secretary modifies or rescinds the determination
or guidance.
(g) ONRR or the Assistant Secretary generally will not
retroactively modify or rescind a value determination issued under
paragraph (d) of this section, unless:
(1) There was a misstatement or omission of material facts; or
(2) The facts subsequently developed are materially different from
the facts on which the guidance was based.
(h) ONRR may make requests and replies under this section available
to the public, subject to the confidentiality requirements under Sec.
1206.109.
Sec. 1206.109 Does ONRR protect information I provide?
(a) Certain information you or your affiliate submit(s) to ONRR
regarding valuation of oil, including transportation allowances, may be
exempt from disclosure.
(b) To the extent applicable laws and regulations permit, ONRR will
keep confidential any data you or your affiliate submit(s) that is
privileged, confidential, or otherwise exempt from disclosure.
(c) You and others must submit all requests for information under
the Freedom of Information Act regulations of the Department of the
Interior at 43 CFR part 2.
Sec. 1206.110 What general transportation allowance requirements
apply to me?
(a) ONRR will allow a deduction for the reasonable, actual costs to
transport oil from the lease to the point off the lease under Sec.
1206.110, Sec. 1206.111, or Sec. 1206.112, as applicable. You may not
deduct transportation costs you incur to move a particular volume of
production to reduce royalties you owe on production for which you did
not incur those costs. This paragraph applies when:
(1) You value oil under Sec. 1206.101 based on a sale at a point
off the lease, unit, or communitized area where the oil is produced;
(2)(i) The movement to the sales point is not gathering.
(ii) For oil produced on the OCS, the movement of oil from the
wellhead to the first platform is not transportation; and
(3) You do not value your oil under Sec. 1206.102(a)(3) or (b)(3).
[[Page 650]]
(b) You must calculate the deduction for transportation costs based
on your or your affiliate's cost of transporting each product through
each individual transportation system. If your or your affiliate's
transportation contract includes more than one liquid product, you must
allocate costs consistently and equitably to each of the liquid
products transported. Your allocation must use the same proportion as
the ratio of the volume of each liquid product (excluding waste
products with no value) to the volume of all liquid products (excluding
waste products with no value).
(1) You may not take an allowance for transporting lease production
that is not royalty-bearing.
(2) You may propose to ONRR a prospective cost allocation method
based on the values of the liquid products transported. ONRR will
approve the method if it is consistent with the purposes of the
regulations in this subpart.
(3) You may use your proposed procedure to calculate a
transportation allowance beginning with the production month following
the month ONRR received your proposed procedure until ONRR accepts or
rejects your cost allocation. If ONRR rejects your cost allocation, you
must amend your Form ONRR-2014 for the months that you used the
rejected method and pay any additional royalty due, plus late payment
interest.
(c)(1) Where you or your affiliate transport(s) both gaseous and
liquid products through the same transportation system, you must
propose a cost allocation procedure to ONRR.
(2) You may use your proposed procedure to calculate a
transportation allowance until ONRR accepts or rejects your cost
allocation. If ONRR rejects your cost allocation, you must amend your
Form ONRR-2014 for the months that you used the rejected method and pay
any additional royalty and interest due.
(3) You must submit your initial proposal, including all available
data, within 3 months after you first claim the allocated deductions on
Form ONRR-2014.
(d)(1) Your transportation allowance may not exceed 50 percent of
the value of the oil as determined under Sec. 1206.101 of this
subpart.
(2) If ONRR approved your request to take a transportation
allowance in excess of the 50-percent limitation under former Sec.
1206.109(c), that approval is terminated as of [effective date of final
rule].
(e) You must express transportation allowances for oil as a dollar-
value equivalent. If your or your affiliate's payments for
transportation under a contract are not on a dollar-per-unit basis, you
must convert whatever consideration you or your affiliate are paid to a
dollar-value equivalent.
(f) ONRR may determine your transportation allowance under Sec.
1206.105 because:
(1) There is misconduct by or between the contracting parties;
(2) ONRR determines that the consideration you or your affiliate
paid under an arm's-length transportation contract does not reflect the
reasonable cost of the transportation because you breached your duty to
market the oil for the mutual benefit of yourself and the lessor by
transporting your oil at a cost that is unreasonably high. We may
consider a transportation allowance to be unreasonably high if it is 10
percent higher than the highest reasonable measures of transportation
costs, including but not limited to, transportation allowances reported
to ONRR and tariffs for gas, residue gas, or gas plant product
transported through the same system; or
(3) ONRR cannot determine if you properly calculated a
transportation allowance under Sec. 1206.111 or Sec. 1206.112 for any
reason, including, but not limited to, your or your affiliate's failure
to provide documents ONRR requests under 30 CFR part 1212, subpart B.
(g) You do not need ONRR approval before reporting a transportation
allowance.
Sec. 1206.111 How do I determine a transportation allowance if I have
an arm's-length transportation contract?
(a)(1) If you or your affiliate incur transportation costs under an
arm's-length transportation contract, you may claim a transportation
allowance for the reasonable, actual costs incurred as more fully
explained in paragraph (b) of this section, except as provided in Sec.
1206.110(f) and subject to the limitation in Sec. 1206.110(d).
(2) You must be able to demonstrate that your or your affiliate's
contract is at arm's-length.
(3) You do not need ONRR approval before reporting a transportation
allowance for costs incurred under an arm's-length transportation
contract.
(b) Subject to the requirements of paragraph (c) of this section,
you may include, but are not limited to the following costs to
determine your transportation allowance under paragraph (a) of this
section. You may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section.
(1) The amount that you pay under your arm's-length transportation
contract or tariff.
(2) Fees paid (either in volume or in value) for actual or
theoretical line losses.
(3) Fees paid for administration of a quality bank.
(4) Fees paid to a terminal operator for loading and unloading of
crude oil into or from a vessel, vehicle, pipeline, or other
conveyance.
(5) Fees paid for short-term storage (30 days or less) incidental
to transportation as required by a transporter.
(6) Fees paid to pump oil to another carrier's system or vehicles
as required under a tariff.
(7) Transfer fees paid to a hub operator associated with physical
movement of crude oil through the hub when you do not sell the oil at
the hub. These fees do not include title transfer fees.
(8) Payments for a volumetric deduction to cover shrinkage when
high-gravity petroleum (generally in excess of 51 degrees API) is mixed
with lower gravity crude oil for transportation.
(9) Costs of securing a letter of credit, or other surety, that the
pipeline requires you as a shipper to maintain.
(10) Hurricane surcharges you or your affiliate actually pay(s).
(c) You may not include the following costs to determine your
transportation allowance under paragraph (a) of this section:
(1) Fees paid for long-term storage (more than 30 days);
(2) Administrative, handling, and accounting fees associated with
terminalling;
(3) Title and terminal transfer fees;
(4) Fees paid to track and match receipts and deliveries at a
market center or to avoid paying title transfer fees;
(5) Fees paid to brokers;
(6) Fees paid to a scheduling service provider;
(7) Internal costs, including salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to
schedule, nominate, and account for sale or movement of production;
(8) Gauging fees; and
(9) The cost of carrying on your books as inventory a volume of oil
that you or your affiliate, as the pipeline operator, maintain(s) in
the line as line fill.
(d) If you have no written contract for the arm's-length
transportation of oil, then ONRR will determine your
[[Page 651]]
transportation allowance under Sec. 1206.105. You may not use this
paragraph (d) if you or your affiliate perform(s) your own
transportation.
(1) You must propose to ONRR a method to determine the allowance
using the procedures in Sec. 1206.108(a).
(2) You may use that method to determine your allowance until ONRR
issues its determination.
Sec. 1206.112 How do I determine a transportation allowance if I do
not have an arm's-length transportation contract?
(a) This section applies if you or your affiliate do(es) not have
an arm's-length transportation contract, including situations where you
or your affiliate provide your own transportation services. You must
calculate your transportation allowance based on your or your
affiliate's reasonable, actual costs for transportation during the
reporting period using the procedures prescribed in this section.
(b) Your or your affiliate's actual costs may include:
(1) Capital costs and operating and maintenance expenses under
paragraphs (e), (f), and (g) of this section;
(2) Overhead under paragraph (h) of this section; and
(3)(i) Depreciation and a return on undepreciated capital
investment under paragraph (i)(1) of this section, or you may elect to
use a cost equal to a return on the initial depreciable capital
investment in the transportation system under paragraph (i)(2) of this
section. After you have elected to use either method for a
transportation system, you may not later elect to change to the other
alternative without ONRR approval. If ONRR accepts your request to
change methods, you may use your changed method beginning with the
production month following the month ONRR received your change request;
and
(ii) A return on the reasonable salvage value under paragraph
(i)(1)(iii) of this section, after you have depreciated the
transportation system to its reasonable salvage value.
(c) To the extent not included in costs identified in paragraphs
(e) through (h) of this section;
(1) If you or your affiliate incur(s) the following actual costs
under your or your affiliate's non-arm's-length contract, you may
include these costs in your calculations under this section.
(i) Fees paid to a non-affiliated terminal operator for loading and
unloading of crude oil into or from a vessel, vehicle, pipeline, or
other conveyance.
(ii) Transfer fees paid to a hub operator associated with physical
movement of crude oil through the hub when you do not sell the oil at
the hub. These fees do not include title transfer fees.
(iii) A volumetric deduction to cover shrinkage when high-gravity
petroleum (generally in excess of 51 degrees API) is mixed with lower
gravity crude oil for transportation.
(iv) Fees paid to a non-affiliated quality bank administrator for
administration of a quality bank.
(2) You may not include in your transportation allowance:
(i) Any of the costs identified under Sec. 1206.111(c); and
(ii) Fees paid (either in volume or in value) for actual or
theoretical line losses.
(d) You may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section.
(e) Allowable capital investment costs are generally those for
depreciable fixed assets (including costs of delivery and installation
of capital equipment) that are an integral part of the transportation
system.
(f) Allowable operating expenses include:
(i) Operations supervision and engineering;
(ii) Operations labor;
(iii) Fuel;
(iv) Utilities;
(v) Materials;
(vi) Ad valorem property taxes;
(vii) Rent;
(viii) Supplies; and
(ix) Any other directly allocable and attributable operating
expense that you can document.
(g) Allowable maintenance expenses include:
(1) Maintenance of the transportation system;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses
that you can document.
(h) Overhead, directly attributable and allocable to the operation
and maintenance of the transportation system, is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(i)(1) To calculate depreciation and a return on undepreciated
capital investment, you may elect to use either a straight-line
depreciation method (based on the life of equipment or on the life of
the reserves that the transportation system services) or a unit of
production method. After you make an election, you may not change
methods without ONRR approval. If ONRR accepts your request to change
methods, you may use your changed method beginning with the production
month following the month ONRR received your change request.
(i) A change in ownership of a transportation system will not alter
the depreciation schedule the original transporter/lessee established
for purposes of the allowance calculation.
(ii) You may depreciate a transportation system, with or without a
change in ownership, only once.
(iii)(A) To calculate the return on undepreciated capital
investment, you may use an amount equal to the undepreciated capital
investment in the transportation system multiplied by the rate of
return you determine under paragraph (i)(3) of this section.
(B) After you have depreciated a transportation system to the
reasonable salvage value, you may continue to include in the allowance
calculation a cost equal to the reasonable salvage value multiplied by
a rate of return under paragraph (i)(3) of this section.
(2) As an alternative to using depreciation and a return on
undepreciated capital investment, as provided under paragraph (b)(3) of
this section, you may use as a cost an amount equal to the allowable
initial capital investment in the transportation system multiplied by
the rate of return determined under paragraph (i)(3) of this section.
You may not include depreciation in your allowance.
(3) The rate of return is the industrial rate associated with
Standard & Poor's BBB rating.
(i) You must use the monthly average BBB rate that Standard &
Poor's publishes for the first month for which the allowance is
applicable.
(ii) You must redetermine the rate at the beginning of each
subsequent calendar year.
Sec. 1206.113 What adjustments and transportation allowances apply
when I value oil production from my lease using NYMEX prices or ANS
spot prices?
This section applies when you use NYMEX prices or ANS spot prices
to calculate the value of production under Sec. 1206.102. As specified
in this section, you must adjust the NYMEX price to reflect the
difference in value between your lease and Cushing, Oklahoma, or adjust
the ANS spot price to reflect the difference in value between your
lease and the appropriate ONRR-recognized market center at which the
ANS spot price is published (for example, Long Beach, California, or
San Francisco, California). Paragraph (a) of this section explains how
you adjust the value between the lease and the market center,
[[Page 652]]
and paragraph (b) of this section explains how you adjust the value
between the market center and Cushing when you use NYMEX prices.
Paragraph (c) of this section explains how adjustments may be made for
quality differentials that are not accounted for through exchange
agreements. Paragraph (d) of this section gives some examples.
References in this section to ``you'' include your affiliates as
applicable.
(a) To adjust the value between the lease and the market center:
(1)(i) For oil that you exchange at arm's-length between your lease
and the market center (or between any intermediate points between those
locations), you must calculate a lease-to-market center differential by
the applicable location and quality differentials derived from your
arm's-length exchange agreement applicable to production during the
production month.
(ii) For oil that you exchange between your lease and the market
center (or between any intermediate points between those locations)
under an exchange agreement that is not at arm's-length, you must
obtain approval from ONRR for a location and quality differential.
Until you obtain such approval, you may use the location and quality
differential derived from that exchange agreement applicable to
production during the production month. If ONRR prescribes a different
differential, you must apply ONRR's differential to all periods for
which you used your proposed differential. You must pay any additional
royalties due resulting from using ONRR's differential, plus late
payment interest from the original royalty due date, or you may report
a credit for any overpaid royalties, plus interest, under 30 U.S.C.
1721(h).
(2) For oil that you transport between your lease and the market
center (or between any intermediate points between those locations),
you may take an allowance for the cost of transporting that oil between
the relevant points as determined under Sec. 1206.111 or Sec.
1206.112, as applicable.
(3) If you transport or exchange at arm's-length (or both transport
and exchange) at least 20 percent, but not all, of your oil produced
from the lease to a market center, you must determine the adjustment
between the lease and the market center for the oil that is not
transported or exchanged (or both transported and exchanged) to or
through a market center as follows:
(i) Determine the volume-weighted average of the lease-to-market
center adjustment calculated under paragraphs (a)(1) and (2) of this
section for the oil that you do transport or exchange (or both
transport and exchange) from your lease to a market center.
(ii) Use that volume-weighted average lease-to-market center
adjustment as the adjustment for the oil that you do not transport or
exchange (or both transport and exchange) from your lease to a market
center.
(4) If you transport or exchange (or both transport and exchange)
less than 20 percent of the crude oil produced from your lease between
the lease and a market center, you must propose to ONRR an adjustment
between the lease and the market center for the portion of the oil that
you do not transport or exchange (or both transport and exchange) to a
market center. Until you obtain such approval, you may use your
proposed adjustment. If ONRR prescribes a different adjustment, you
must apply ONRR's adjustment to all periods for which you used your
proposed adjustment. You must pay any additional royalties due
resulting from using ONRR's adjustment, plus late payment interest from
the original royalty due date, or you may report a credit for any
overpaid royalties plus interest under 30 U.S.C. 1721(h).
(5) You may not both take a transportation allowance and use a
location and quality adjustment or exchange differential for the same
oil between the same points.
(b) For oil that you value using NYMEX prices, you must adjust the
value between the market center and Cushing, Oklahoma, as follows:
(1) If you have arm's-length exchange agreements between the market
center and Cushing under which you exchange to Cushing at least 20
percent of all the oil you own at the market center during the
production month, you must use the volume-weighted average of the
location and quality differentials from those agreements as the
adjustment between the market center and Cushing for all the oil that
you produce from the leases during that production month for which that
market center is used.
(2) If paragraph (b)(1) of this section does not apply, you must
use the WTI differential published in an ONRR-approved publication for
the market center nearest your lease, for crude oil most similar in
quality to your production, as the adjustment between the market center
and Cushing. For example, for light sweet crude oil produced offshore
of Louisiana, you must use the WTI differential for Light Louisiana
Sweet crude oil at St. James, Louisiana. After you select an ONRR-
approved publication, you may not select a different publication more
often than once every 2 years, unless the publication you use is no
longer published or ONRR revokes its approval of the publication. If
you must change publications, you must begin a new 2-year period.
(3) If neither paragraph (b)(1) nor (2) of this section applies,
you may propose an alternative differential to ONRR. Until you obtain
such approval, you may use your proposed differential. If ONRR
prescribes a different differential, you must apply ONRR's differential
to all periods for which you used your proposed differential. You must
pay any additional royalties due resulting from using ONRR's
differential, plus late payment interest from the original royalty due
date, or you may report a credit for any overpaid royalties plus
interest under 30 U.S.C. 1721(h).
(c)(1) If you adjust for location and quality differentials or for
transportation costs under paragraphs (a) and (b) of this section, you
also must adjust the NYMEX price or ANS spot price for quality based on
premiums or penalties determined by pipeline quality bank
specifications at intermediate commingling points or at the market
center if those points are downstream of the royalty measurement point
approved by BSEE or BLM, as applicable. You must make this adjustment
only if and to the extent that such adjustments were not already
included in the location and quality differentials determined from your
arm's-length exchange agreements.
(2) If the quality of your oil as adjusted is still different from
the quality of the representative crude oil at the market center after
making the quality adjustments described in paragraphs (a), (b), and
(c)(1) of this section, you may make further gravity adjustments using
posted price gravity tables. If quality bank adjustments do not
incorporate or provide for adjustments for sulfur content, you may make
sulfur adjustments, based on the quality of the representative crude
oil at the market center, of 5.0 cents per one-tenth percent difference
in sulfur content.
(i) You may request prior ONRR approval to use a different
adjustment.
(ii) If ONRR approves your request to use a different quality
adjustment, you may begin using that adjustment the production month
following the month ONRR received your request.
(d) The examples in this paragraph illustrate how to apply the
requirement of this section.
(1) Example. Assume that a Federal lessee produces crude oil from a
lease near Artesia, New Mexico. Further, assume that the lessee
transports the oil
[[Page 653]]
to Roswell, New Mexico, and then exchanges the oil to Midland, Texas.
Assume the lessee refines the oil received in exchange at Midland.
Assume that the NYMEX price is $86.21/bbl, adjusted for the roll; that
the WTI differential (Cushing to Midland) is -$2.27/bbl; that the
lessee's exchange agreement between Roswell and Midland results in a
location and quality differential of -$0.08/bbl; and that the lessee's
actual cost of transporting the oil from Artesia to Roswell is $0.40/
bbl. In this example, the royalty value of the oil is $86.21 - $2.27 -
$0.08 - $0.40 = $83.46/bbl.
(2) Example. Assume the same facts as in the example in paragraph
(d)(1) of this section, except that the lessee transports and exchanges
to Midland 40 percent of the production from the lease near Artesia,
and transports the remaining 60 percent directly to its own refinery in
Ohio. In this example, the 40 percent of the production would be valued
at $83.46/bbl, as explained in the previous example. In this example,
the other 60 percent also would be valued at $83.46/bbl.
(3) Example. Assume that a Federal lessee produces crude oil from a
lease near Bakersfield, California. Further, assume that the lessee
transports the oil to Hynes Station and then exchanges the oil to
Cushing, which it further exchanges with oil it refines. Assume that
the ANS spot price is $105.65/bbl and that the lessee's actual cost of
transporting the oil from Bakersfield to Hynes Station is $0.28/bbl.
The lessee must request approval from ONRR for a location and quality
adjustment between Hynes Station and Long Beach. For example, the
lessee likely would propose using the tariff on Line 63 from Hynes
Station to Long Beach as the adjustment between those points. Assume
that adjustment to be $0.72, including the sulfur and gravity bank
adjustments, and that ONRR approves the lessee's request. In this
example, the preliminary (because the location and quality adjustment
is subject to ONRR review) royalty value of the oil is $105.65 - $0.72
- $0.28 = $104.65/bbl. The fact that oil was exchanged to Cushing does
not change use of ANS spot prices for royalty valuation.
Sec. 1206.114 How will ONRR identify market centers?
ONRR will monitor market activity and, if necessary, add to or
modify the list of market centers published to www.onrr.gov. ONRR will
consider the following factors and conditions in specifying market
centers:
(a) Points where ONRR-approved publications publish prices useful
for index purposes;
(b) Markets served;
(c) Input from industry and others knowledgeable in crude oil
marketing and transportation;
(d) Simplification; and
(e) Other relevant matters.
Sec. 1206.115 What are my reporting requirements under an arm's-
length transportation contract?
(a) You must use a separate entry on Form ONRR-2014 to notify ONRR
of an allowance based on transportation costs you or your affiliate
incur(s).
(b) ONRR may require you or your affiliate to submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents.
(c) You can find recordkeeping requirements in parts 1207 and 1212
of this chapter.
Sec. 1206.116 What are my reporting requirements under a non-arm's-
length transportation contract?
(a) You must use a separate entry on Form ONRR-2014 to notify ONRR
of an allowance based on transportation costs you or your affiliate
incur(s).
(b)(1) For new non-arm's-length transportation facilities or
arrangements, you must base your initial deduction on estimates of
allowable transportation costs for the applicable period.
(2) You must use your or your affiliate's most recently available
operations data for the transportation system as your estimate, if
available. If such data is not available, you must use estimates based
on data for similar transportation systems.
(3) Section 1206.118 applies when you amend your report based on
the actual costs.
(c) ONRR may require you or your affiliate to submit all data used
to calculate the allowance deduction. You may find recordkeeping
requirements in parts 1207 and 1212 of this chapter.
(d) If you are authorized under Sec. 1206.112(j) to use an
exception to the requirement to calculate your actual transportation
costs, you must follow the reporting requirements of Sec. 1206.115.
Sec. 1206.117 What interest and penalties apply if I improperly
report a transportation allowance?
(a) If you deduct a transportation allowance on Form ONRR-2014 that
exceeds 50 percent of the value of the oil transported, you must pay
additional royalties due, plus late payment interest calculated under
Sec. Sec. 1218.54 and 1218.102 of this chapter, on the excess
allowance amount taken from the date that amount is taken to the date
you pay the additional royalties due.
(b) If you improperly net a transportation allowance against the
oil instead of reporting the allowance as a separate entry on Form
ONRR-2014, ONRR may assess a civil penalty under 30 CFR part 1241.
Sec. 1206.118 What reporting adjustments must I make for
transportation allowances?
(a) If your actual transportation allowance is less than the amount
you claimed on Form ONRR-2014 for each month during the allowance
reporting period, you must pay additional royalties due, plus late
payment interest calculated under Sec. Sec. 1218.54 and 1218.102 of
this chapter from the date you took the deduction to the date you repay
the difference.
(b) If the actual transportation allowance is greater than the
amount you claimed on Form ONRR-2014 for any month during the period
reported on the allowance form, you are entitled to a credit plus
interest.
Sec. 1206.119 How do I determine royalty quantity and quality?
(a) You must calculate royalties based on the quantity and quality
of oil as measured at the point of royalty settlement that BLM or BSEE
approves for onshore leases and OCS leases, respectively.
(b) If you base the value of oil determined under this subpart on a
quantity and/or quality that is different from the quantity and/or
quality at the point of royalty settlement that BLM or BSEE approves,
you must adjust that value for the differences in quantity and/or
quality.
(c) You may not make any deductions from the royalty volume or
royalty value for actual or theoretical losses. Any actual loss that
you sustain before the royalty settlement metering or measurement point
is not subject to royalty if BLM or BSEE, whichever is appropriate,
determines that such loss was unavoidable.
(d) You must pay royalties on 100 percent of the volume measured at
the approved point of royalty settlement. You may not claim a reduction
in that measured volume for actual losses beyond the approved point of
royalty settlement or for theoretical losses that you claim to have
taken place either before or after the approved point of royalty
settlement.
0
7. Revise subpart D to read as follows:
Subpart D--Federal Gas
Sec.
1206.140 What is the purpose and scope of this subpart?
[[Page 654]]
1206.141 How do I calculate royalty value for unprocessed gas I or
my affiliate sell(s) under an arm's-length or non-arm's-length
contract?
1206.142 How do I calculate royalty value for processed gas I or my
affiliate sell(s) under an arm's-length or non-arm's-length
contract?
1206.143 How will ONRR determine if my royalty payments are correct?
1206.144 How will ONRR determine the value of my gas for royalty
purposes?
1206.145 What records must I keep to support my calculations of
royalty under this subpart?
1206.146 What are my responsibilities to place production into
marketable condition and to market production?
1206.147 When is an ONRR audit, review, reconciliation, monitoring,
or other like process considered final?
1206.148 How do I request a valuation determination or guidance?
1206.149 Does ONRR protect information I provide?
1206.150 How do I determine royalty quantity and quality?
1206.151 How do I perform accounting for comparison?
1206.152 What general transportation allowance requirements apply to
me?
1206.153 How do I determine a transportation allowance if I have an
arm's-length transportation contract?
1206.154 How do I determine a transportation allowance if I have a
non-arm's-length transportation contract?
1206.155 What are my reporting requirements under an arm's-length
transportation contract?
1206.156 What are my reporting requirements under a non-arm's-length
transportation contract?
1206.157 What interest and penalties apply if I improperly report a
transportation allowance?
1206.158 What reporting adjustments must I make for transportation
allowances?
1206.159 What general requirements regarding processing allowances
apply to me?
1206.160 How do I determine a processing allowance, if I have an
arm's-length processing contract?
1206.161 How do I determine a processing allowance if I have a non-
arm's-length processing contract?
1206.162 What are my reporting requirements under an arm's-length
processing contract?
1206.163 What are my reporting requirements under a non-arm's-length
processing contract?
1206.164 What interest and penalties apply if I improperly report a
processing allowance?
1206.165 What reporting adjustments must I make for processing
allowances?
Subpart D--Federal Gas
Sec. 1206.140 What is the purpose and scope of this subpart?
(a) This subpart applies to all gas produced from Federal oil and
gas leases onshore and on the Outer Continental Shelf (OCS). It
explains how you, as a lessee, must calculate the value of production
for royalty purposes consistent with mineral leasing laws, other
applicable laws, and lease terms.
(b) The terms ``you'' and ``your'' in this subpart refer to the
lessee.
(c) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee
resulting from administrative or judicial litigation;
(3) A written agreement between the lessee and the ONRR Director
establishing a method to determine the value of production from any
lease that ONRR expects, at least, would approximate the value
established under this subpart; or
(4) An express provision of an oil and gas lease subject to this
subpart; then the statute, settlement agreement, written agreement, or
lease provision will govern to the extent of the inconsistency.
(d) ONRR may audit and order you to adjust all royalty payments.
Sec. 1206.141 How do I calculate royalty value for unprocessed gas I
or my affiliate sell(s) under an arm's-length or non-arm's-length
contract?
(a) This section applies to unprocessed gas. Unprocessed gas is:
(1) Gas that is not processed;
(2) Any gas that you are not required to value under Sec. 1206.142
or that ONRR does not value under Sec. 1206.144;
(3) Processed gas that you must value prior to processing under
Sec. 1206.151 of this part; and
(4) Any gas you sell prior to processing based on a price per MMBtu
or Mcf when the price is not based on the residue gas and gas plant
products.
(b) The value of gas under this section for royalty purposes is the
gross proceeds accruing to you or your affiliate under the first arm's-
length contract less an applicable transportation allowance determined
under Sec. 1206.152. This value does not apply if you may exercise the
option provided in paragraph (c) of this section or if ONRR decides to
value your gas under Sec. 1206.144. You must use this paragraph (b) to
value gas when:
(1) You sell under an arm's-length contract;
(2) You sell or transfer to your affiliate or another person under
a non-arm's-length contract and that affiliate or person, or another
affiliate of either of them, then sells the gas under an arm's-length
contract, unless you exercise the option provided in paragraph (c) of
this section;
(3) You, your affiliate, or another person sell(s) under multiple
arm's-length contracts for gas produced from a lease that is valued
under this paragraph. In that case, unless you exercise the option
provided in paragraph (c) of this section, because you sold non-arm's
length to your affiliate or another person, the value of the gas is the
volume-weighted average of the value established under this paragraph
for each contract for the sale of gas produced from that lease; or
(4) You or your affiliate sell(s) under a pipeline cash-out
program. In that case, for over-delivered volumes within the tolerance
under a pipeline cash-out program, the value is the price the pipeline
must pay you or your affiliate under the transportation contract. You
must use the same value for volumes that exceed the over-delivery
tolerances, even if those volumes are subject to a lower price under
the transportation contract.
(c) If you do not sell under an arm's-length contract, you may
elect to value your gas under this paragraph (c). You may not change
your election more often than once every two years.
(1)(i) If you can only transport gas to one index pricing point
published in an ONRR-approved publication, available at www.onrr.gov,
your value, for royalty purposes, is the highest reported monthly
bidweek price for that index pricing point for the production month.
(ii) If you can transport gas to more than one index pricing point
published in an ONRR-approved publication, available at www.onrr.gov,
your value, for royalty purposes, is the highest reported monthly
bidweek price for the index pricing points to which your gas could be
transported for the production month, whether or not there are
constraints for that production month.
(iii) If there are sequential index pricing points on a pipeline,
you must use the first index pricing point at or after your gas enters
the pipeline.
(iv) You must reduce the number calculated under paragraphs
(c)(1)(i) and (c)(1)(ii) of this section by 5 percent for sales from
the OCS Gulf of Mexico and by 10 percent for sales from all other
areas, but not by less than 10 cents per MMBtu or more than 30 cents
per MMBtu.
(v) After you select an ONRR-approved publication available at
www.onrr.gov, you may not select a different publication more often
than once every two years.
(vi) ONRR may exclude an individual index pricing point found in an
ONRR-approved publication, if ONRR determines that the index pricing
point does not accurately reflect the values of
[[Page 655]]
production. ONRR will publish a list of excluded index pricing points
available at www.onrr.gov.
(2) You may not take any other deductions from the value calculated
under this paragraph (c).
(d) If you have no written contract for the sale of gas or no sale
of gas subject to this section and:
(1) There is an index pricing point for the gas, then you must
value your gas under paragraph (c) of this section;
(2) There is not an index pricing point for the gas, then ONRR will
decide the value under Sec. 1206.144.
(i) You must propose to ONRR a method to determine the value using
the procedures in Sec. 1206.148(a).
(ii) You may use that method to determine value, for royalty
purposes, until ONRR issues its decision.
(iii) After ONRR issues its determination, you must make the
adjustments under Sec. 1206.143(a)(2).
Sec. 1206.142 How do I calculate royalty value for processed gas I or
my affiliate sell(s) under an arm's-length or non-arm's-length
contract?
(a) This section applies to the valuation of processed gas,
including but not limited to:
(1) Gas you or your affiliate do not sell, or otherwise dispose of,
under an arm's-length contract prior to processing;
(2) Gas where your or your affiliate's arm's-length contract for
the sale of gas prior to processing provides for payment to be
determined on the basis of the value of any products resulting from
processing, including residue gas or natural gas liquids;
(3) Gas you or your affiliate process under an arm's-length
keepwhole contract; and
(4) Gas where your or your affiliate's arm's-length contract
includes a reservation of the right to process the gas and you or your
affiliate exercise(s) that right.
(b) The value of gas subject to this section, for royalty purposes,
is:
(1) The combined value of the residue gas and all gas plant
products you determine under this section;
(2) Plus the value of any condensate recovered downstream of the
point of royalty settlement without resorting to processing you
determine under Sec. 1206.141 of this part;
(3) Less applicable transportation and processing allowances you
determine under this subpart, unless you exercise the option provided
in paragraph (d) of this section.
(c) The value of residue gas or any gas plant product under this
section for royalty purposes is the gross proceeds accruing to you or
your affiliate under the first arm's-length contract. This value does
not apply if you exercise the option provided in paragraph (d) of this
section, or if ONRR decides to value your residue gas or any gas plant
product under Sec. 1206.144. You must use this paragraph (c) to value
residue gas or any gas plant product when:
(1) You sell under an arm's-length contract;
(2) You sell or transfer to your affiliate or another person under
a non-arm's-length contract, and that affiliate or person, or another
affiliate of either of them then sells the residue gas or any gas plant
product under an arm's-length contract, unless you exercise the option
provided in paragraph (d) of this section;
(3) You, your affiliate, or another person sell(s) under multiple
arm's-length contracts for residue gas or any gas plant products
recovered from gas produced from a lease that you value under this
paragraph. In that case, unless you exercise the option provided in
paragraph (d) of this section, because you sold non-arm's-length to
your affiliate or another person, the value of the residue gas or any
gas plant product is the volume-weighted average of the gross proceeds
established under this paragraph for each arm's-length contract for the
sale of residue gas or any gas plant products recovered from gas
produced from that lease; or
(4) You or your affiliate sell(s) under a pipeline cash-out
program. In that case, for over-delivered volumes within the tolerance
under a pipeline cash-out program, the value is the price the pipeline
must pay you or your affiliate under the transportation contract. You
must use the same value for volumes that exceed the over-delivery
tolerances, even if those volumes are subject to a lower price under
the transportation contract.
(d) If you do not sell under an arm's-length contract, you may
elect to value your residue gas and natural gas liquids (NGLS) under
this paragraph (d). You may not change your election more often than
once every two years.
(1)(i) If you can only transport residue gas to one index pricing
point published in an ONRR-approved publication, available at
www.onrr.gov, your value, for royalty purposes, is the highest reported
monthly bidweek price for that index pricing point for the production
month.
(ii) If you can transport residue gas to more than one index
pricing point published in an ONRR-approved publication, available at
www.onrr.gov, your value, for royalty purposes, is the highest reported
monthly bidweek price for the index pricing points to which your gas
could be transported for the production month, whether or not there are
constraints, for the production month.
(iii) If there are sequential index pricing points on a pipeline,
you must use the first index pricing point at or after your residue gas
enters the pipeline.
(iv) You must reduce the number calculated under paragraphs
(d)(1)(i) and (ii) of this section by 5 percent for sales from the OCS
Gulf of Mexico and by 10 percent for sales from all other areas, but
not by less than 10 cents per MMBtu or more than 30 cents per MMBtu.
(v) After you select an ONRR-approved publication available at
www.onrr.gov, you may not select a different publication more often
than once every two years.
(vi) ONRR may exclude an individual index pricing point found in an
ONRR-approved publication, if ONRR determines that the index pricing
point does not accurately reflect the values of production. ONRR will
publish a list of excluded index pricing points available at
www.onrr.gov.
(2)(i) If you sell NGLs in an area with one or more ONRR-approved
commercial price bulletins available at www.onrr.gov, you must choose
one bulletin and your value, for royalty purposes, is the monthly
average price for that bulletin for the production month.
(ii) You must reduce the number calculated under paragraph
(d)(2)(i) of this section by the amounts ONRR posts at www.onrr.gov for
the geographic location of your lease. The methodology ONRR will use to
calculate the amounts is set forth in the preamble to this regulation.
This methodology is binding on you and ONRR. ONRR will update the
amounts periodically using this methodology.
(iii) After you select an ONRR-approved commercial price bulletin
available at www.onrr.gov, you may not select a different commercial
price bulletin more often than once every 2 years.
(3) You may not take any other deductions from the value calculated
under this paragraph (d).
(4) ONRR will post changes to any of the rates in this paragraph
(d) on its Web site.
(e) If you have no written contract for the sale of gas or no sale
of gas subject to this section and:
(1) There is an index pricing point or commercial price bulletin
for the gas, then you must value your gas under paragraph (d) of this
section.
[[Page 656]]
(2) There is not an index pricing point or commercial price
bulletin for the gas, then ONRR will determine the value under Sec.
1206.144.
(i) You must propose to ONRR a method to determine the value using
the procedures in Sec. 1206.148(a).
(ii) You may use that method to determine value, for royalty
purposes, until ONRR issues its decision.
(iii) After ONRR issues its determination, you must make the
adjustments under Sec. 1206.143(a)(2).
Sec. 1206.143 How will ONRR determine if my royalty payments are
correct?
(a)(1) ONRR may monitor, review, and audit the royalties you
report. If ONRR determines that your reported value is inconsistent
with the requirements of this subpart, ONRR will direct you to use a
different measure of royalty value or decide your value under Sec.
1206.144.
(2) If ONRR directs you to use a different royalty value, you must
either pay any additional royalties due, plus late payment interest
calculated under Sec. Sec. 1218.54 and 1218.102 of this chapter or
report a credit for, or request a refund of, any overpaid royalties.
(b) When the provisions in this subpart refer to gross proceeds, in
conducting reviews and audits, ONRR will examine if your or your
affiliate's contract reflects the total consideration actually
transferred, either directly or indirectly, from the buyer to you or
your affiliate for the gas, residue gas, or gas plant products. If ONRR
determines that a contract does not reflect the total consideration,
ONRR may decide your value under Sec. 1206.144.
(c) ONRR may decide your value under Sec. 1206.144, if ONRR
determines that the gross proceeds accruing to you or your affiliate
under a contract do not reflect reasonable consideration because:
(1) There is misconduct by or between the contracting parties;
(2) You have breached your duty to market the gas, residue gas, or
gas plant products for the mutual benefit of yourself and the lessor by
selling your gas, residue gas, or gas plant products at a value that is
unreasonably low. ONRR may consider a sales price unreasonably low, if
it is 10 percent less than the lowest reasonable measures of market
price, including but not limited to, index prices and prices reported
to ONRR for like-quality gas, residue gas, or gas plant products; or
(3) ONRR cannot determine if you properly valued your gas, residue
gas, or gas plant products under Sec. 1206.141 or Sec. 1206.142 for
any reason, including but not limited to, your or your affiliate's
failure to provide documents ONRR requests under 30 CFR part 1212,
subpart B.
(d) You have the burden of demonstrating that your or your
affiliate's contract is arm's length.
(e) ONRR may require you to certify that the provisions in your or
your affiliate's contract include(s) all of the consideration the buyer
paid you or your affiliate, either directly or indirectly, for the gas,
residue gas, or gas plant products.
(f)(1) Absent contract revision or amendment, if you or your
affiliate fail(s) to take proper or timely action to receive prices or
benefits to which you or your affiliate are entitled, you must pay
royalty based upon that obtainable price or benefit.
(2) If you or your affiliate make timely application for a price
increase or benefit allowed under your or your affiliate's contract,
but the purchaser refuses, and you or your affiliate take reasonable
documented measures to force purchaser compliance, you will not owe
additional royalties unless or until you or your affiliate receive
additional monies or consideration resulting from the price increase.
You may not construe this paragraph to permit you to avoid your royalty
payment obligation in situations where a purchaser fails to pay, in
whole or in part, or timely, for a quantity of gas, residue gas, or gas
plant products.
(g)(1) You or your affiliate must make all contracts, contract
revisions, or amendments in writing, and all parties to the contract
must sign the contract, contract revisions, or amendments.
(2) If you or your affiliate fail(s) to comply with paragraph
(g)(1) of this section, ONRR may decide your value under Sec.
1206.144.
(3) This provision applies notwithstanding any other provisions in
this title 30 to the contrary.
Sec. 1206.144 How will ONRR determine the value of my gas for royalty
purposes?
If ONRR decides to value your gas, residue gas, or gas plant
products for royalty purposes under Sec. 1206.143, or any other
provision in this subpart, then ONRR will determine the value, for
royalty purposes, by considering any information we deem relevant,
which may include, but is not limited to:
(a) The value of like-quality gas in the same field or nearby
fields or areas;
(b) The value of like-quality residue gas or gas plant products
from the same plant or area;
(c) Public sources of price or market information that ONRR deems
reliable;
(d) Information available or reported to ONRR, including but not
limited to, on Form ONRR-2014 and Form ONRR-4054;
(e) Costs of transportation or processing, if ONRR determines they
are applicable; or
(f) Any information ONRR deems relevant regarding the particular
lease operation or the salability of the gas.
Sec. 1206.145 What records must I keep to support my calculations of
royalty under this subpart?
If you value your gas under this subpart, you must retain all data
relevant to the determination of the royalty you paid. You can find
recordkeeping requirements in parts 1207 and 1212 of this chapter.
(a) You must show:
(1) How you calculated the royalty value, including all allowable
deductions; and
(2) How you complied with this subpart.
(b) Upon request, you must submit all data to ONRR. You must comply
with any such requirement within the time ONRR specifies.
Sec. 1206.146 What are my responsibilities to place production into
marketable condition and to market production?
(a) You must place gas, residue gas, and gas plant products in
marketable condition and market the gas, residue gas, and gas plant
products for the mutual benefit of the lessee and the lessor at no cost
to the Federal Government.
(b) If you use gross proceeds under an arm's-length contract to
determine royalty, you must increase those gross proceeds to the extent
that the purchaser, or any other person, provides certain services that
you normally are responsible to perform to place the gas, residue gas,
and gas plant products in marketable condition or to market the gas.
Sec. 1206.147 When is an ONRR audit, review, reconciliation,
monitoring, or other like process considered final?
Notwithstanding any provision in these regulations to the contrary,
ONRR does not consider any audit, review, reconciliation, monitoring,
or other like process that results in ONRR redetermining royalty due,
under this subpart, final or binding as against the Federal Government
or its beneficiaries unless ONRR chooses to formally close the audit
period in writing.
Sec. 1206.148 How do I request a valuation determination or guidance?
(a) You may request a valuation determination or guidance from ONRR
regarding any gas produced. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, all interest owners
of those
[[Page 657]]
leases, the designee(s), and the operator(s) for those leases;
(3) Completely explain all relevant facts. You must inform ONRR of
any changes to relevant facts that occur before we respond to your
request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to
all relevant precedents (including adverse precedents); and
(6) Suggest your proposed valuation method.
(b) In response to your request, ONRR may:
(1) Request that the Assistant Secretary for Policy, Management and
Budget issue a determination; or
(2) Decide that ONRR will issue guidance; or
(3) Inform you in writing that ONRR will not provide a
determination or guidance. Situations in which ONRR typically will not
provide any determination or guidance include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or
administrative appeals.
(c)(1) A determination the Assistant Secretary for Policy,
Management and Budget signs is binding on both you and ONRR until the
Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a determination, you must
make any adjustments to royalty payments that follow from the
determination and, if you owe additional royalties, you must pay the
additional royalties due, plus late payment interest calculated under
Sec. Sec. 1218.54 and 1218.102 of this chapter.
(3) A determination the Assistant Secretary signs is the final
action of the Department and is subject to judicial review under 5
U.S.C. 701-706.
(d) Guidance ONRR issues is not binding on ONRR, delegated States,
or you with respect to the specific situation addressed in the
guidance.
(1) Guidance and ONRR's decision whether or not to issue guidance
or request an Assistant Secretary determination, or neither, under
paragraph (b) of this section, are not appealable decisions or orders
under 30 CFR part 1290.
(2) If you receive an order requiring you to pay royalty on the
same basis as the guidance, you may appeal that order under 30 CFR part
1290.
(e) ONRR or the Assistant Secretary may use any of the applicable
criteria in this subpart to provide guidance or make a determination.
(f) A change in an applicable statute or regulation on which ONRR
based any guidance, or the Assistant Secretary based any determination,
takes precedence over the determination or guidance after the effective
date of the statute or regulation, regardless of whether ONRR or the
Assistant Secretary modifies or rescinds the guidance or determination.
(g) ONRR may make requests and replies under this section available
to the public, subject to the confidentiality requirements under Sec.
1206.149.
Sec. 1206.149 Does ONRR protect information I provide?
(a) Certain information you or your affiliate submit(s) to ONRR
regarding royalties on gas, including deductions and allowances, may be
exempt from disclosure.
(b) To the extent applicable laws and regulations permit, ONRR will
keep confidential any data you or your affiliate submit(s) that is
privileged, confidential, or otherwise exempt from disclosure.
(c) You and others must submit all requests for information under
the Freedom of Information Act regulations of the Department of the
Interior at 43 CFR part 2.
Sec. 1206.150 How do I determine royalty quantity and quality?
(a)(1) You must calculate royalties based on the quantity and
quality of unprocessed gas as measured at the point of royalty
settlement that BLM or BSEE approves for onshore leases and OCS leases,
respectively.
(2) If you base the value of gas determined under this subpart on a
quantity and/or quality that is different from the quantity and/or
quality at the point of royalty settlement that BLM or BSEE approves,
you must adjust that value for the differences in quantity and/or
quality.
(b)(1) For residue gas and gas plant products, the quantity basis
for computing royalties due is the monthly net output of the plant,
even though residue gas and/or gas plant products may be in temporary
storage.
(2) If you value residue gas and/or gas plant products determined
under this subpart on a quantity and/or quality of residue gas and/or
gas plant products that is different from that which is attributable to
a lease determined under paragraph (c) of this section, you must adjust
that value for the differences in quantity and/or quality.
(c) You must determine the quantity of the residue gas and gas
plant products attributable to a lease based on the following
procedure:
(1) When you derive the net output of the processing plant from gas
obtained from only one lease, you must base the quantity of the residue
gas and gas plant products for royalty computation on the net output of
the plant.
(2) When you derive the net output of a processing plant from gas
obtained from more than one lease producing gas of uniform content, you
must base the quantity of the residue gas and gas plant products
allocable to each lease on the same proportions as the ratios obtained
by dividing the amount of gas delivered to the plant from each lease by
the total amount of gas delivered from all leases.
(3) When the net output of a processing plant is derived from gas
obtained from more than one lease producing gas of non-uniform content:
(i) You must determine the quantity of the residue gas allocable to
each lease by multiplying the amount of gas delivered to the plant from
the lease by the residue gas content of the gas, and dividing that
arithmetical product by the sum of the similar arithmetical products
separately obtained for all leases from which gas is delivered to the
plant, and then multiplying the net output of the residue gas by the
arithmetic quotient obtained.
(ii) You must determine the net output of gas plant products
allocable to each lease by multiplying the amount of gas delivered to
the plant from the lease by the gas plant product content of the gas,
and dividing that arithmetical product by the sum of the similar
arithmetical products separately obtained for all leases from which gas
is delivered to the plant, and then multiplying the net output of each
gas plant product by the arithmetic quotient obtained.
(4) You may request prior ONRR approval of other methods for
determining the quantity of residue gas and gas plant products
allocable to each lease. If approved, you must apply that method to all
gas production from Federal leases that is processed in the same plant
beginning with the production month following the month ONRR received
your request to use another method.
(d)(1) You may not make any deductions from the royalty volume or
royalty value for actual or theoretical losses. Any actual loss of
unprocessed gas that you sustain before the royalty settlement meter or
measurement point is not subject to royalty; if BLM or BSEE, whichever
is appropriate, determines that such loss was unavoidable.
(2) Except as provided in paragraph (d)(1) of this section and
Sec. 1202.151(c), you must pay royalties due on 100 percent of the
volume determined under paragraphs (a) through (c) of this
[[Page 658]]
section. You may not reduce that determined volume for actual losses
after you have determined the quantity basis, or for theoretical losses
that you claim to have taken place. Royalties are due on 100 percent of
the value of the unprocessed gas, residue gas, and/or gas plant
products, as provided in this subpart, less applicable allowances. You
may not take any deduction from the value of the unprocessed gas,
residue gas, and/or gas plant products to compensate for actual losses
after you have determined the quantity basis or for theoretical losses
that you claim to have taken place.
Sec. 1206.151 How do I perform accounting for comparison?
(a) Except as provided in paragraph (b) of this section, if you or
your affiliate (or a person to whom you have transferred gas under a
non-arm's-length contract or without a contract) processes your or your
affiliate's gas and after processing the gas, you or your affiliate do
not sell the residue gas under an arm's-length contract, the value, for
royalty purposes, will be the greater of:
(1) The combined value, for royalty purposes, of the residue gas
and gas plant products resulting from processing the gas determined
under Sec. 1206.142 of this subpart, plus the value, for royalty
purposes, of any condensate recovered downstream of the point of
royalty settlement without resorting to processing determined under
Sec. 1206.102 of this subpart; or
(2) The value, for royalty purposes, of the gas prior to processing
as determined under Sec. 1206.141 of this subpart.
(b) The requirement for accounting for comparison contained in the
terms of leases will govern as provided in Sec. 1206.142(a)(2) of this
subpart.
(c) When lease terms require accounting for comparison, you must
perform accounting for comparison under paragraph (a) of this section.
Sec. 1206.152 What general transportation allowance requirements
apply to me?
(a) ONRR will allow a deduction for the reasonable, actual costs to
transport residue gas, gas plant products, or unprocessed gas from the
lease to the point off the lease under Sec. 1206.153 or Sec.
1206.154, as applicable. You may not deduct transportation costs you
incur to move a particular volume of production to reduce royalties you
owe on production for which you did not incur those costs. This
paragraph applies when:
(1) You value unprocessed gas under Sec. 1206.141(b) or residue
gas and gas plant products under Sec. 1206.142(b) based on a sale at a
point off the lease, unit, or communitized area where the residue gas,
gas plant products, or unprocessed gas is produced; and
(2)(i) The movement to the sales point is not gathering.
(ii) For gas produced on the OCS, the movement of gas from the
wellhead to the first platform is not transportation.
(b) You must calculate the deduction for transportation costs based
on your or your affiliate's cost of transporting each product through
each individual transportation system. If your or your affiliate's
transportation contract includes more than one product in a gaseous
phase, you must allocate costs consistently and equitably to each of
the products transported. Your allocation must use the same proportion
as the ratio of the volume of each product (excluding waste products
with no value) to the volume of all products in the gaseous phase
(excluding waste products with no value).
(1) You may not take an allowance for transporting lease production
that is not royalty-bearing.
(2) You may propose to ONRR a prospective cost allocation method
based on the values of the products transported. ONRR will approve the
method, if it is consistent with the purposes of the regulations in
this subpart.
(3) You may use your proposed procedure to calculate a
transportation allowance beginning with the production month following
the month ONRR received your proposed procedure until ONRR accepts or
rejects your cost allocation. If ONRR rejects your cost allocation, you
must amend your Form ONRR-2014 for the months that you used the
rejected method and pay any additional royalty due, plus late payment
interest calculated under Sec. Sec. 1218.54 and 1218.102 of this
chapter.
(c)(1) Where you or your affiliate transport(s) both gaseous and
liquid products through the same transportation system, you must
propose a cost allocation procedure to ONRR.
(2) You may use your proposed procedure to calculate a
transportation allowance until ONRR accepts or rejects your cost
allocation. If ONRR rejects your cost allocation, you must amend your
Form ONRR-2014 for the months that you used the rejected method and pay
any additional royalty due, plus late payment interest calculated under
Sec. Sec. 1218.54 and 1218.102 of this chapter.
(3) You must submit your initial proposal, including all available
data, within 3 months after you first claim the allocated deductions on
Form ONRR-2014.
(d) If you value unprocessed gas under Sec. 1206.141(c) or residue
gas and gas plant products under Sec. 1206.142 (d), you may not take a
transportation allowance.
(e)(1) Your transportation allowance may not exceed 50 percent of
the value of the residue gas, gas plant products, or unprocessed gas as
determined under Sec. 1206.141 or Sec. 1206.142 of this subpart.
(2) If ONRR approved your request to take a transportation
allowance in excess of the 50-percent limitation under former Sec.
1206.156(c)(3), that approval is terminated as of the effective date of
the final rule.
(f) You must express transportation allowances for residue gas, gas
plant products, or unprocessed gas as a dollar-value equivalent. If
your or your affiliate's payments for transportation under a contract
are not on a dollar-per-unit basis, you must convert whatever
consideration you or your affiliate are paid to a dollar-value
equivalent.
(g) ONRR may determine your transportation allowance under Sec.
1206.144 because:
(1) There is misconduct by or between the contracting parties;
(2) ONRR determines that the consideration you or your affiliate
paid under an arm's-length transportation contract does not reflect the
reasonable cost of the transportation because you breached your duty to
market the gas, residue gas, or gas plant products for the mutual
benefit of yourself and the lessor by transporting your gas, residue
gas, or gas plant products at a cost that is unreasonably high. We may
consider a transportation allowance unreasonably high if it is 10-
percent higher than the highest reasonable measures of transportation
costs including, but not limited to, transportation allowances reported
to ONRR and tariffs for gas, residue gas, or gas plant products
transported through the same system; or
(3) ONRR cannot determine if you properly calculated a
transportation allowance under Sec. 1206.153 or Sec. 1206.154 for any
reason, including but not limited to, you or your affiliate's failure
to provide documents ONRR requests under 30 CFR part 1212, subpart B.
(h) You do not need ONRR approval before reporting a transportation
allowance.
Sec. 1206.153 How do I determine a transportation allowance if I have
an arm's-length transportation contract?
(a)(1) If you or your affiliate incur transportation costs under an
arm's-length transportation contract, you may claim a transportation
allowance for the reasonable, actual costs incurred as
[[Page 659]]
more fully explained in paragraph (b) of this section, except as
provided in Sec. 1206.152(g) and subject to the limitation in Sec.
1206.152(e).
(2) You must be able to demonstrate that your or your affiliate's
contract is arm's-length.
(b) Subject to the requirements of paragraph (c) of this section,
you may include, but are not limited to, the following costs to
determine your transportation allowance under paragraph (a) of this
section. You may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section.
(1) Firm demand charges paid to pipelines. You may deduct firm
demand charges or capacity reservation fees you or your affiliate paid
to a pipeline, including charges or fees for unused firm capacity you
or your affiliate have not sold before you report your allowance. If
you or your affiliate receive(s) a payment from any party for release
or sale of firm capacity after reporting a transportation allowance
that included the cost of that unused firm capacity, or if you or your
affiliate receive(s) a payment or credit from the pipeline for penalty
refunds, rate case refunds, or other reasons, you must reduce the firm
demand charge claimed on the Form ONRR-2014 by the amount of that
payment. You must modify the Form ONRR-2014 by the amount received or
credited for the affected reporting period, and pay any resulting
royalty due, plus late payment interest calculated under Sec. Sec.
1218.54 and 1218.102 of this chapter;
(2) Gas supply realignment (GSR) costs. The GSR costs result from a
pipeline reforming or terminating supply contracts with producers to
implement the restructuring requirements of FERC Orders in 18 CFR part
284;
(3) Commodity charges. The commodity charge allows the pipeline to
recover the costs of providing service;
(4) Wheeling costs. Hub operators charge a wheeling cost for
transporting gas from one pipeline to either the same or another
pipeline through a market center or hub. A hub is a connected manifold
of pipelines through which a series of incoming pipelines are
interconnected to a series of outgoing pipelines;
(5) Gas Research Institute (GRI) fees. The GRI conducts research,
development, and commercialization programs on natural gas related
topics for the benefit of the U.S. gas industry and gas customers. GRI
fees are allowable provided such fees are mandatory in FERC-approved
tariffs;
(6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to
pipelines to pay for its operating expenses;
(7) Payments (either volumetric or in value) for actual or
theoretical losses. However, theoretical losses are not deductible in
transportation arrangements unless the transportation allowance is
based on arm's-length transportation rates charged under a FERC- or
State regulatory-approved tariff, or ONRR approves your use of a FERC
or State regulatory-approved tariff as an exception from the
requirement to calculate actual costs under Sec. 1206.154(l) of this
subpart. If you or your affiliate receive(s) volumes or credit for line
gain, you must reduce your transportation allowance accordingly and pay
any resulting royalties, plus late payment interest calculated under
Sec. Sec. 1218.54 and 1218.102 of this chapter;
(8) Temporary storage services. This includes short duration
storage services offered by market centers or hubs (commonly referred
to as ``parking'' or ``banking''), or other temporary storage services
provided by pipeline transporters, whether actual or provided as a
matter of accounting. Temporary storage is limited to 30 days or less;
(9) Supplemental costs for compression, dehydration, and treatment
of gas. ONRR allows these costs only if such services are required for
transportation and exceed the services necessary to place production
into marketable condition required under Sec. 1206.146 of this part;
(10) Costs of surety. You may deduct the costs of securing a letter
of credit, or other surety, that the pipeline requires you or your
affiliate as a shipper to maintain under a transportation contract; and
(11) Hurricane Surcharges. You may deduct hurricane surcharges you
or your affiliate actually pay(s).
(c) You may not include the following costs to determine your
transportation allowance under paragraph (a) of this section:
(1) Fees or costs incurred for storage. This includes storing
production in a storage facility, whether on or off the lease, for more
than 30 days;
(2) Aggregator/marketer fees. This includes fees you or your
affiliate pay(s) to another person (including your affiliates) to
market your gas, including purchasing and reselling the gas, or finding
or maintaining a market for the gas production;
(3) Penalties you or your affiliate incur(s) as shipper. These
penalties include, but are not limited to:
(i) Over-delivery cash-out penalties. This includes the difference
between the price the pipeline pays you or your affiliate for over-
delivered volumes outside the tolerances and the price you or your
affiliate receive(s) for over-delivered volumes within the tolerances;
(ii) Scheduling penalties. This includes penalties you or your
affiliate incur(s) for differences between daily volumes delivered into
the pipeline and volumes scheduled or nominated at a receipt or
delivery point;
(iii) Imbalance penalties. This includes penalties you or your
affiliate incur(s) (generally on a monthly basis) for differences
between volumes delivered into the pipeline and volumes scheduled or
nominated at a receipt or delivery point; and
(iv) Operational penalties. This includes fees you or your
affiliate incur(s) for violation of the pipeline's curtailment or
operational orders issued to protect the operational integrity of the
pipeline.
(4) Intra-hub transfer fees. These are fees you or your affiliate
pay(s) to hub operators for administrative services (e.g., title
transfer tracking) necessary to account for the sale of gas within a
hub;
(5) Fees paid to brokers. This includes fees you or your affiliate
pay(s) to parties who arrange marketing or transportation, if such fees
are separately identified from aggregator/marketer fees;
(6) Fees paid to scheduling service providers. This includes fees
you or your affiliate pay(s) to parties who provide scheduling
services, if such fees are separately identified from aggregator/
marketer fees;
(7) Internal costs. This includes salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to
schedule, nominate, and account for sale or movement of production; and
(8) Other nonallowable costs. Any cost you or your affiliate
incur(s) for services you are required to provide at no cost to the
lessor, including but not limited to, costs to place your gas, residue
gas, or gas plant products into marketable condition disallowed under
Sec. 1206.146 and costs of boosting residue gas disallowed under 30
CFR 1202.151(b).
(d) If you have no written contract for the transportation of gas,
then ONRR will determine your transportation allowance under Sec.
1206.144. You may not use this paragraph (d), if you or your affiliate
perform(s) your own transportation.
[[Page 660]]
(1) You must propose to ONRR a method to determine the allowance
using the procedures in Sec. 1206.148(a).
(2) You may use that method to determine your allowance until ONRR
issues its determination.
Sec. 1206.154 How do I determine a transportation allowance if I have
a non-arm's-length transportation contract?
(a) This section applies if you or your affiliate do(es) not have
an arm's-length transportation contract, including situations where you
or your affiliate provide your own transportation services. You must
calculate your transportation allowance based on your or your
affiliate's reasonable, actual costs for transportation during the
reporting period using the procedures prescribed in this section.
(b) Your or your affiliate's actual costs may include:
(1) Capital costs and operating and maintenance expenses under
paragraphs (e), (f), and (g) of this section;
(2) Overhead under paragraph (h) of this section;
(3) Depreciation and a return on undepreciated capital investment
under paragraph (i)(1) of this section, or you may elect to use a cost
equal to a return on the initial depreciable capital investment in the
transportation system under paragraph (i)(2) of this section. After you
have elected to use either method for a transportation system, you may
not later elect to change to the other alternative without ONRR
approval. If ONRR accepts your request to change methods, you may use
your changed method beginning with the production month following the
month ONRR received your change request; and
(4) A return on the reasonable salvage value under paragraph
(i)(1)(iii) of this section, after you have depreciated the
transportation system to its reasonable salvage value.
(c)(1) To the extent not included in costs identified in paragraphs
(e) through (g) of this section, if you or your affiliate incur(s) the
actual transportation costs listed under Sec. 1206.153(b)(2), (5), and
(6) of this subpart under your or your affiliate's non-arm's-length
contract, you may include those costs in your calculations under this
section. You may not include any of the other costs identified under
Sec. 1206.153 (b); and
(2) You may not include in your calculations under this section any
of the nonallowable costs listed under Sec. 1206.153(c).
(d) You may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section.
(e) Allowable capital investment costs are generally those for
depreciable fixed assets (including costs of delivery and installation
of capital equipment) that are an integral part of the transportation
system.
(f) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating expense
that you can document.
(g) Allowable maintenance expenses include:
(i) Maintenance of the transportation system;
(ii) Maintenance of equipment;
(iii) Maintenance labor; and
(iv) Other directly allocable and attributable maintenance expenses
that you can document.
(h) Overhead, directly attributable and allocable to the operation
and maintenance of the transportation system, is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(i)(1) To calculate depreciation and a return on undepreciated
capital investment, you may elect to use either a straight-line
depreciation method based on the life of equipment or on the life of
the reserves that the transportation system services, or a unit of
production method. After you make an election, you may not change
methods without ONRR approval. If ONRR accepts your request to change
methods, you may use your changed method beginning with the production
month following the month ONRR received your change request.
(i) A change in ownership of a transportation system will not alter
the depreciation schedule the original transporter/lessee established
for purposes of the allowance calculation.
(ii) You may depreciate a transportation system only once with or
without a change in ownership.
(iii)(A) To calculate the return on undepreciated capital
investment, you may use an amount equal to the undepreciated capital
investment in the transportation system multiplied by the rate of
return you determine under paragraph (i)(3) of this section.
(B) After you have depreciated a transportation system to the
reasonable salvage value, you may continue to include in the allowance
calculation a cost equal to the reasonable salvage value multiplied by
a rate of return under paragraph (i)(3) of this section.
(2) As an alternative to using depreciation and a return on
undepreciated capital investment, as provided under paragraph (b)(3) of
this section, you may use as a cost an amount equal to the allowable
initial capital investment in the transportation system multiplied by
the rate of return determined under paragraph (i)(3) of this section.
You may not include depreciation in your allowance.
(3) The rate of return is the industrial rate associated with
Standard & Poor's BBB rating.
(i) You must use the monthly average that BBB rate Standard &
Poor's publishes for the first month for which the allowance is
applicable.
(ii) You must redetermine the rate at the beginning of each
subsequent calendar year.
Sec. 1206.155 What are my reporting requirements under an arm's-
length transportation contract?
(a) You must use a separate entry on Form ONRR-2014 to notify ONRR
of an allowance based on transportation costs you or your affiliate
incur(s).
(b) ONRR may require you or your affiliate to submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents.
(c) You can find recordkeeping requirements in parts 1207 and 1212
of this chapter.
Sec. 1206.156 What are my reporting requirements under a non-arm's-
length transportation contract?
(a) You must use a separate entry on Form ONRR-2014 to notify ONRR
of an allowance based on non-arm's-length transportation costs you or
your affiliate incur(s).
(b)(1) For new non-arm's-length transportation facilities or
arrangements, you must base your initial deduction on estimates of
allowable transportation costs for the applicable period.
(2) You must use your or your affiliate's most recently available
operations data for the transportation system as your estimate. If such
data is not available, you must use estimates based on data for similar
transportation systems.
(3) Section 1206.158 applies when you amend your report based on
your actual costs.
(c) ONRR may require you or your affiliate to submit all data used
to calculate the allowance deduction. You
[[Page 661]]
can find recordkeeping requirements in parts 1207 and 1212 of this
chapter.
(d) If you are authorized under Sec. 1206.154(j) to use an
exception to the requirement to calculate your actual transportation
costs, you must follow the reporting requirements of Sec. 1206.155.
Sec. 1206.157 What interest and penalties apply if I improperly
report a transportation allowance?
(a)(1) If ONRR determines that you took an unauthorized
transportation allowance, then you must pay any additional royalties
due, plus late payment interest calculated under Sec. Sec. 1218.54 and
1218.102 of this chapter.
(2) If you understated your transportation allowance, you may be
entitled to a credit with interest.
(b) If you deduct a transportation allowance on Form ONRR-2014 that
exceeds 50 percent of the value of the gas, residue gas, or gas plant
products transported, you must pay late payment interest on the excess
allowance amount taken from the date that amount is taken until the
date you pay the additional royalties due.
(c) If you improperly net a transportation allowance against the
sales value of the residue gas, gas plant products, or unprocessed gas
instead of reporting the allowance as a separate entry on Form ONRR-
2014, ONRR may assess a civil penalty under 30 CFR part 1241.
Sec. 1206.158 What reporting adjustments must I make for
transportation allowances?
(a) If your actual transportation allowance is less than the amount
you claimed on Form ONRR-2014 for each month during the allowance
reporting period, you must pay additional royalties due, plus late
payment interest calculated under Sec. Sec. 1218.54 and 1218.102 of
this chapter from the date you took the deduction to the date you repay
the difference.
(b) If the actual transportation allowance is greater than the
amount you claimed on Form ONRR-2014 for any month during the period
reported on the allowance form, you are entitled to a credit plus
interest.
Sec. 1206.159 What general processing allowances requirements apply
to me?
(a)(1) When you value any gas plant product under Sec. 1206.142(c)
of this subpart, you may deduct from value the reasonable actual costs
of processing.
(2) You do not need ONRR approval before reporting a processing
allowance.
(b) You must allocate processing costs among the gas plant
products. You must determine a separate processing allowance for each
gas plant product and processing plant relationship. ONRR considers
NGLs one product.
(c)(1) You may not apply the processing allowance against the value
of the residue gas.
(2) The processing allowance deduction on the basis of an
individual product may not exceed 66\2/3\ percent of the value of each
gas plant product determined under Sec. 1206.142(c). Before you
calculate the 66\2/3\ percent limit, you must first reduce the value
for any transportation allowances related to post-processing
transportation authorized under Sec. 1206.152.
(3) If ONRR approved your request to take a processing allowance in
excess of the limitation in paragraph (c)(2) of this section under
former Sec. 1206.158(c)(3), that approval is terminated as of
[EFFECTIVE DATE OF FINAL RULE].
(4) If ONRR approved your request to take an extraordinary cost
processing allowance under former Sec. 1206.158(d), ONRR terminates
that approval as of [EFFECTIVE DATE OF FINAL RULE].
(d)(1) ONRR will not allow a processing cost deduction for the
costs of placing lease products in marketable condition, including
dehydration, separation, compression, or storage, even if those
functions are performed off the lease or at a processing plant.
(2) Where gas is processed for the removal of acid gases, commonly
referred to as ``sweetening,'' ONRR will not allow processing cost
deductions for such costs unless the acid gases removed are further
processed into a gas plant product.
(A) In such event, you are eligible for a processing allowance
determined under this subpart.
(B) ONRR will not grant any processing allowance for processing
lease production that is not royalty bearing.
Sec. 1206.160 How do I determine a processing allowance, if I have an
arm's-length processing contract?
(a)(1) If you or your affiliate incur processing costs under an
arm's-length processing contract, you may claim a processing allowance
for the reasonable, actual costs incurred as more fully explained in
paragraph (b) of this section, except as provided in paragraphs
(a)(3)(1) and (a)(3)(ii) of this section and subject to the limitation
in Sec. 1206.159(c)(2).
(2) You must be able to demonstrate that your or your affiliate's
contract is arm's length.
(3) ONRR may determine your processing allowance under Sec.
1206.144, if:
(i) ONRR determines that your or your affiliate's contract reflects
more than the consideration actually transferred either directly or
indirectly from you or your affiliate to the processor for processing;
or
(ii) ONRR determines that the consideration you or your affiliate
paid under an arm's-length processing contract does not reflect the
reasonable cost of the processing because you breached your duty to
market the gas for the mutual benefit of yourself and the lessor by
processing your gas at a cost that is unreasonably high. We may
consider a processing allowance unreasonably high, if it is 10-percent
higher than the highest reasonable measures of processing costs,
including but not limited to processing allowances reported to ONRR for
gas processed in the same plant or area.
(b)(1) If your or your affiliate's arm's-length processing contract
includes more than one gas plant product and you can determine the
processing costs for each product based on the contract, then you must
determine the processing costs for each gas plant product under the
contract.
(2) If your or your affiliate's arm's-length processing contract
includes more than one gas plant product and you cannot determine the
processing costs attributable to each product from the contract, you
must propose an allocation procedure to ONRR.
(i) You may use your proposed allocation procedure until ONRR
issues its determination.
(ii) You must submit all relevant data to support your proposal.
(iii) ONRR will determine the processing allowance based upon your
proposal and any additional information ONRR deems necessary.
(iv) You must submit the allocation proposal within 3 months of
claiming the allocated deduction on Form ONRR-2014.
(3) You may not take an allowance for the costs of processing lease
production that is not royalty-bearing.
(4) If your or your affiliate's payments for processing under an
arm's-length contract are not based on a dollar-per-unit basis, you
must convert whatever consideration you or your affiliate paid to a
dollar-value equivalent.
(c) If you have no written contract for the arm's-length processing
of gas, then ONRR will determine your processing allowance under Sec.
1206.144. You may not use this paragraph (c) if you or your affiliate
perform(s) your own processing.
(1) You must propose to ONRR a method to determine the allowance
using the procedures in Sec. 1206.148(a).
(2) You may use that method to determine your allowance until ONRR
issues a determination.
[[Page 662]]
Sec. 1206.161 How do I determine a processing allowance if I have a
non-arm's-length processing contract?
(a) This section applies if you or your affiliate do(es) not have
an arm's-length processing contract, including situations where you or
your affiliate provide your own processing services. You must calculate
your processing allowance based on you or your affiliate's reasonable,
actual costs for processing during the reporting period using the
procedures prescribed in this section.
(b) You or your affiliate's actual costs include the following:
(1) Capital costs and operating and maintenance expenses under
paragraphs (d), (e), and (f) of this section;
(2) Overhead under paragraph (g) of this section;
(3) Depreciation and a return on undepreciated capital investment
in accordance with paragraph (h)(1) of this section, or you may elect
to use a cost equal to the initial depreciable capital investment in
the processing plant under paragraph (h)(2) of this section. After you
have elected to use either method for a processing plant, you may not
later elect to change to the other alternative without ONRR approval.
If ONRR accepts your request to change methods, you may use your
changed method beginning with the production month following the month
ONRR received your change request; and
(4) A return on the reasonable salvage value under paragraph
(h)(1)(iii) of this section, after you have depreciated the processing
plant to its reasonable salvage value.
(c) You may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section.
(d) Allowable capital investment costs are generally those for
depreciable fixed assets (including costs of delivery and installation
of capital equipment), which are an integral part of the processing
plant.
(e) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating expense
that you can document.
(f) Allowable maintenance expenses include:
(1) Maintenance of the processing plant;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses
that you can document.
(g) Overhead, directly attributable and allocable to the operation
and maintenance of the processing plant, is an allowable expense. State
and Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(h)(1) To calculate depreciation and a return on undepreciated
capital investment, you may elect to use either a straight-line
depreciation method based on the life of equipment or on the life of
the reserves which the processing plant services, or a unit-of-
production method. After you make an election, you may not change
methods without ONRR approval. If ONRR accepts your request to change
methods, you may use your changed method beginning with the production
month following the month ONRR received your change request.
(i) A change in ownership of a processing plant will not alter the
depreciation schedule that the original processor/lessee established
for purposes of the allowance calculation.
(ii) You may depreciate a processing plant only once with or
without a change in ownership.
(iii)(A) To calculate a return on undepreciated capital investment,
you may use an amount equal to the undepreciated capital investment in
the processing plant multiplied by the rate of return you determine
under paragraph (h)(3) of this section.
(B) After you have depreciated a processing plant to its reasonable
salvage value, you may continue to include in the allowance calculation
a cost equal to the reasonable salvage value multiplied by a rate of
return under paragraph (h)(3) of this section.
(2) You may use as a cost an amount equal to the allowable initial
capital investment in the processing plant multiplied by the rate of
return determined under paragraph (h)(3) of this section. You may not
include depreciation in your allowance.
(3) The rate of return is the industrial rate associated with
Standard & Poor's BBB rating.
(i) You must use the monthly average that BBB rate Standard &
Poor's publishes for the first month for which the allowance is
applicable.
(ii) You must redetermine the rate at the beginning of each
subsequent calendar year.
(i)(1) You must determine the processing allowance for each gas
plant product based on your or your affiliate's reasonable and actual
cost of processing the gas. You must base your allocation of costs to
each gas plant product upon generally accepted accounting principles.
(2) You may not take an allowance for processing lease production
that is not royalty-bearing.
(j) You may apply for an exception from the requirement to
calculate actual costs under paragraphs (a) and (b) of this section.
(1) ONRR will grant the exception, if:
(i) You have or your affiliate has arm's-length contracts for
processing other gas production at the same processing plant; and
(ii) At least 50-percent of the gas processed annually at the plant
is processed under arm's-length processing contracts.
(2) If ONRR grants the exception, you must use as your processing
allowance the volume-weighted average prices charged other persons
under arm's-length contracts for processing at the same plant.
Sec. 1206.162 What are my reporting requirements under an arm's-
length processing contract?
(a) You must use a separate entry on Form ONRR-2014 to notify ONRR
of an allowance based on arm's-length processing costs you or your
affiliate incur(s).
(b) ONRR may require you or your affiliate to submit arm's-length
processing contracts, production agreements, operating agreements, and
related documents.
(c) You can find recordkeeping requirements in parts 1207 and 1212
of this chapter.
Sec. 1206.163 What are my reporting requirements under a non-arm's-
length processing contract?
(a) You must use a separate entry on Form ONRR-2014 to notify ONRR
of an allowance based on non-arm's-length processing costs you or your
affiliate incur(s).
(b)(1) For new non-arm's-length processing facilities or
arrangements, you must base your initial deduction on estimates of
allowable gas processing costs for the applicable period.
(2) You must use your or your affiliate's most recently available
operations data for the processing plant as your estimate, if
available. If such data is not available, you must use estimates based
on data for similar processing plants.
(3) Section 1206.165 applies when you amend your report based on
your actual costs.
(c) ONRR may require you or your affiliate to submit all data used
to
[[Page 663]]
calculate the allowance deduction. You can find recordkeeping
requirements in parts 1207 and 1212 of this chapter.
(d) If you are authorized under Sec. 1206.161(j) to use an
exception to the requirement to calculate your actual processing costs,
you must follow the reporting requirements of Sec. 1206.162.
Sec. 1206.164 What interest and penalties apply if I improperly
report a processing allowance?
(a)(1) If ONRR determines that you took an unauthorized processing
allowance, then you must pay any additional royalties due, plus late
payment interest calculated under Sec. Sec. 1218.54 and 1218.102 of
this chapter.
(2) If you understated your processing allowance, you may be
entitled to a credit with interest.
(b) If you deduct a processing allowance on Form ONRR-2014 that
exceeds 66\2/3\ percent of the value of a gas plant product, you must
pay late payment interest on the excess allowance amount taken from the
date that amount is taken until the date you pay the additional
royalties due.
(c) If you improperly net a processing allowance against the sales
value of a gas plant product instead of reporting the allowance as a
separate entry on Form ONRR-2014, ONRR may assess a civil penalty under
30 CFR part 1241.
Sec. 1206.165 What reporting adjustments must I make for processing
allowances?
(a) If your actual processing allowance is less than the amount you
claimed on Form ONRR-2014 for each month during the allowance reporting
period, you must pay additional royalties due, plus late payment
interest calculated under Sec. Sec. 1218.54 and 1218.102 of this
chapter from the date you took the deduction to the date you repay the
difference.
(b) If the actual processing allowance is greater than the amount
you claimed on Form ONRR-2014 for any month during the period reported
on the allowance form, you are entitled to a credit plus interest.
0
8. Revise subpart F to read as follows:
Subpart F--Federal Coal
Sec.
1206.250 What is the purpose and scope of this subpart?
1206.251 How do I determine royalty quantity and quality?
1206.252 How do I calculate royalty value for coal I or my affiliate
sell(s) under an arm's-length or non-arm's-length contract?
1206.253 How will ONRR determine if my royalty payments are correct?
1206.254 How will ONRR determine the value of my coal for royalty
purposes?
1206.255 What records must I keep to support my calculations of
royalty under this subpart?
1206.256 What are my responsibilities to place production into
marketable condition and to market production?
1206.257 When is an ONRR audit, review, reconciliation, monitoring,
or other like process considered final?
1206.258 How do I request a valuation determination or guidance?
1206.259 Does ONRR protect information I provide?
1206.260 What general transportation allowance requirements apply to
me?
1206.261 How do I determine a transportation allowance if I have an
arm's-length transportation contract or no written arm's-length
contract?
1206.262 How do I determine a transportation allowance if I have a
non-arm's-length transportation contract?
1206.263 What are my reporting requirements under an arm's-length
transportation contract?
1206.264 What are my reporting requirements under a non-arm's-length
transportation contract?
1206.265 What interest and penalties apply if I improperly report a
transportation allowance?
1206.266 What reporting adjustments must I make for transportation
allowances?
1206.267 What general washing allowance requirements apply to me?
1206.268 How do I determine washing allowances if I have an arm's-
length washing contract or no written arm's-length contract?
1206.269 How do I determine washing allowances if I have a non-
arm's-length washing contract?
1206.270 What are my reporting requirements under an arm's-length
washing contract?
1206.271 What are my reporting requirements under a non-arm's-length
washing contract?
1206.272 What interest and penalties apply if I improperly report a
washing allowance?
1206.273 What reporting adjustments must I make for washing
allowances?
Subpart F--Federal Coal
Sec. 1206.250 What is the purpose and scope of this subpart?
(a) This subpart applies to all coal produced from Federal coal
leases. It explains how you, as the lessee, must calculate the value of
production for royalty purposes consistent with the mineral leasing
laws, other applicable laws and lease terms.
(b) The terms ``you'' and ``your'' in this subpart refer to the
lessee.
(c) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee
resulting from administrative or judicial litigation;
(3) A written agreement between the lessee and the ONRR Director
establishing a method to determine the value of production from any
lease that ONRR expects, at least, would approximate the value
established under this subpart; or
(4) An express provision of a coal lease subject to this subpart,
then the statute, settlement agreement, written agreement, or lease
provision will govern to the extent of the inconsistency.
(d) ONRR may audit and order you to adjust all royalty payments.
Sec. 1206.251 How do I determine royalty quantity and quality?
(a) You must calculate royalties based on the quantity and quality
of coal at the royalty measurement point that ONRR and BLM jointly
determine.
(b) You must measure coal in short tons using the methods BLM
prescribes for Federal coal leases under 43 CFR part 3000. You must
report coal quantity on appropriate forms required in 30 CFR part
1210--Forms and Reports.
(c)(1) You are not required to pay royalties on coal you produce
and add to stockpiles or inventory until you use, sell, or otherwise
finally dispose of such coal.
(2) ONRR may request BLM to require you to increase your lease bond
if BLM determines that stockpiles or inventory are excessive such that
they increase the risk of resource degradation.
(d) You must pay royalty at the rate specified in your lease at the
time you use, sell, or otherwise finally dispose of the coal.
(e) You must allocate washed coal by attributing the washed coal to
the leases from which it was extracted.
(1) If the wash plant washes coal from only one lease, the quantity
of washed coal allocable to the lease is the total output of washed
coal from the plant.
(2) If the wash plant washes coal from more than one lease, you
must determine the tonnage of washed coal attributable to each lease
by:
(i) First, calculating the input ratio of washed coal allocable to
each lease by dividing the tonnage of coal you input to the wash plant
from each lease by the total tonnage of coal input to the wash plant
from all leases; and
(ii) Then multiplying the input ratio derived under paragraph
(e)(2)(i) of this section by the tonnage of total output of washed coal
from the plant.
Sec. 1206.252 How do I calculate royalty value for coal I or my
affiliate sell(s) under an arm's-length or non-arm's-length contract?
(a) The value of coal under this section for royalty purposes is
the gross
[[Page 664]]
proceeds accruing to you or your affiliate under the first arm's-length
contract less an applicable transportation allowance determined under
Sec. Sec. 1206.260 through 1206.262 and washing allowance under
Sec. Sec. 1206.267 through 1206.269. You must use this paragraph (a)
to value coal when:
(1) You sell under an arm's-length contract; or
(2) You sell or transfer to your affiliate or another person under
a non-arm's-length contract, and that affiliate or person, or another
affiliate of either of them, then sells the coal under an arm's-length
contract.
(b) If you have no contract for the sale of coal subject to this
section because you or your affiliate used the coal in a power plant
you or your affiliate own(s) for the generation and sale of electricity
and;
(1) You or your affiliate sell(s) the electricity, then the value
of the coal subject to this section, for royalty purposes, is the gross
proceeds accruing to you for the power plant's arm's-length sales of
the electricity less applicable transportation and washing deductions
determined under Sec. Sec. 1206.260 through 1206.262 and Sec. Sec.
1206.267 through 1206.269 of this subpart and, if applicable,
transmission and generation deductions determined under Sec. Sec.
1206.353 and 1206.352 of subpart H;
(2) You or your affiliate do(es) not sell the electricity at arm's
length (i.e. you or your affiliate deliver(s) the electricity directly
to the grid), then ONRR will determine the value of the coal under
Sec. 1206.254.
(i) You must propose to ONRR a method to determine the value using
the procedures in Sec. 1206.258(a).
(ii) You may use that method to determine value, for royalty
purposes, until ONRR issues a determination.
(iii) After ONRR issues a determination, you must make the
adjustments under Sec. 1206.253(a)(2).
(c) If you are a coal cooperative, or a member of a coal
cooperative, and:
(1) You sell or transfer coal to another member of the coal
cooperative, and that member of the coal cooperative then sells the
coal under an arm's-length contract, then you must value the coal under
paragraph (a) of this section; or
(2) You sell or transfer coal to another member of the coal
cooperative and the coal is used by you, the coal cooperative, or
another member of the coal cooperative in a power plant for the
generation and sale of electricity, then you must value the coal under
paragraph (b) of this section.
(d) If you are entitled to take a washing allowance and
transportation allowance for royalty purposes under this section, under
no circumstances may the washing allowance plus the transportation
allowance reduce the royalty value of the coal to zero.
(e) The values in this section do not apply, if ONRR decides to
value your coal under Sec. 1206.254.
Sec. 1206.253 How will ONRR determine if my royalty payments are
correct?
(a)(1) ONRR may monitor, review, and audit the royalties you
report. If ONRR determines that your reported value is inconsistent
with the requirements of this subpart, ONRR will direct you to use a
different measure of royalty value, or decide your value, under Sec.
1206.254.
(2) If ONRR directs you to use a different royalty value, you must
either pay any underpaid royalties due, plus late payment interest
calculated under Sec. 1218.202 of this chapter or report a credit for,
or request a refund of, any overpaid royalties.
(b) When the provisions in this subpart refer to gross proceeds, in
conducting reviews and audits, ONRR will examine if your or your
affiliate's contract reflects the total consideration actually
transferred, either directly or indirectly, from the buyer to you or
your affiliate for the coal. If ONRR determines that a contract does
not reflect the total consideration, ONRR may decide your value under
Sec. 1206.254.
(c) ONRR may decide to value your coal under Sec. 1206.254 if ONRR
determines that the gross proceeds accruing to you or your affiliate
under a contract do not reflect reasonable consideration because:
(1) There is misconduct by or between the contracting parties;
(2) You breached your duty to market the coal for the mutual
benefit of yourself and the lessor by selling your coal at a value that
is unreasonably low. ONRR may consider a sales price unreasonably low
if it is 10-percent less than the lowest other reasonable measures of
market price, including but not limited to, prices reported to ONRR for
like-quality coal; or
(3) ONRR cannot determine if you properly valued your coal under
Sec. 1206.252 for any reason, including but not limited to, your or
your affiliate's failure to provide documents to ONRR under 30 CFR part
1212, subpart E.
(d) You have the burden of demonstrating that your or your
affiliate's contract is arm's length.
(e) ONRR may require you to certify that the provisions in your or
your affiliate's contract include(s) all of the consideration the buyer
paid you or your affiliate, either directly or indirectly, for the
coal.
(f)(1) Absent contract revision or amendment, if you or your
affiliate fail(s) to take proper or timely action to receive prices or
benefits to which you or your affiliate are entitled, you must pay
royalty based upon that obtainable price or benefit.
(2) If you or your affiliate make timely application for a price
increase or benefit allowed under your or your affiliate's contract,
but the purchaser refuses, and you or your affiliate take reasonable
documented measures to force purchaser compliance, you will not owe
additional royalties unless or until you or your affiliate receive
additional monies or consideration resulting from the price increase.
You may not construe this paragraph to permit you to avoid your royalty
payment obligation in situations where a purchaser fails to pay, in
whole or in part, or timely, for a quantity of coal.
(g)(1) You or your affiliate must make all contracts, contract
revisions, or amendments in writing, and all parties to the contract
must sign the contract, contract revisions, or amendments.
(2) If you or your affiliate fail(s) to comply with paragraph
(g)(1) of this section, ONRR may decide to value your coal under Sec.
1206.254.
(3) This provision applies notwithstanding any other provisions in
this title 30 to the contrary.
Sec. 1206.254 How will ONRR determine the value of my coal for
royalty purposes?
If ONRR decides to value your coal for royalty purposes under Sec.
1206.254, or any other provision in this subpart, then ONRR will
determine value by considering any information we deem relevant, which
may include, but is not limited to:
(a) The value of like-quality coal from the same mine, nearby
mines, same region, or other regions, or washed in the same or nearby
wash plant;
(b) Public sources of price or market information that ONRR deems
reliable, including but not limited to, the price of electricity;
(c) Information available to ONRR and information reported to it,
including but not limited to, on Form ONRR-4430;
(d) Costs of transportation or washing, if ONRR determines they are
applicable; or
(e) Any other information ONRR deems relevant regarding the
particular lease operation or the salability of the coal.
[[Page 665]]
Sec. 1206.255 What records must I keep to support my calculations of
royalty under this subpart?
If you value your coal under this subpart, you must retain all data
relevant to the determination of the royalty you paid. You can find
recordkeeping requirements in parts 1207 and 1212 of this chapter.
(a) You must show:
(1) How you calculated the royalty value, including all allowable
deductions; and
(2) How you complied with this subpart.
(b) Upon request, you must submit all data to ONRR. You must comply
with any such requirement within the time ONRR specifies.
Sec. 1206.256 What are my responsibilities to place production into
marketable condition and to market production?
(a) You must place coal in marketable condition and market the coal
for the mutual benefit of the lessee and the lessor at no cost to the
Federal Government.
(b) If you use gross proceeds under an arm's-length contract to
determine royalty, you must increase those gross proceeds to the extent
that the purchaser, or any other person, provides certain services that
you normally are responsible to perform to place the coal in marketable
condition or to market the coal.
Sec. 1206.257 When is an ONRR audit, review, reconciliation,
monitoring, or other like process considered final?
Notwithstanding any provision in these regulations to the contrary,
ONRR will not consider any audit, review, reconciliation, monitoring,
or other like process that results in ONRR redetermining royalty due,
under this subpart, final or binding as against the Federal Government
or its beneficiaries unless ONRR chooses to formally close the audit
period in writing.
Sec. 1206.258 How do I request a valuation determination or guidance?
(a) You may request a valuation determination or guidance from ONRR
regarding any coal produced. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, all interest owners
of those leases, and the operator(s) for those leases;
(3) Completely explain all relevant facts. You must inform ONRR of
any changes to relevant facts that occur before we respond to your
request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to
all relevant precedents (including adverse precedents); and
(6) Suggest a proposed valuation method.
(b) In response to your request, ONRR may:
(1) Request that the Assistant Secretary for Policy, Management and
Budget issue a determination; or
(2) Decide that ONRR will issue guidance; or
(3) Inform you in writing that ONRR will not provide a
determination or guidance. Situations in which ONRR typically will not
provide any determination or guidance include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or
administrative appeals.
(c)(1) A determination the Assistant Secretary for Policy,
Management and Budget signs is binding on both you and ONRR until the
Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a determination, you must
make any adjustments in royalty payments that follow from the
determination and, if you owe additional royalties, you must pay any
additional royalties due, plus late payment interest calculated under
Sec. 1218.202 of this chapter.
(3) A determination the Assistant Secretary signs is the final
action of the Department and is subject to judicial review under 5
U.S.C. 701-706.
(d) Guidance ONRR issues is not binding on ONRR, delegated States,
or you with respect to the specific situation addressed in the
guidance.
(1) Guidance and ONRR's decision whether or not to issue guidance
or request an Assistant Secretary determination, or neither, under
paragraph (b) of this section, are not appealable decisions or orders
under 30 CFR part 1290.
(2) If you receive an order requiring you to pay royalty on the
same basis as the guidance, you may appeal that order under 30 CFR part
1290.
(e) ONRR or the Assistant Secretary may use any of the applicable
criteria in this subpart to provide guidance or make a determination.
(f) A change in an applicable statute or regulation on which ONRR
based any guidance, or the Assistant Secretary based any determination,
takes precedence over the determination or guidance after the effective
date of the statute or regulation, regardless of whether ONRR or the
Assistant Secretary modifies or rescinds the guidance or determination.
(g) ONRR may make requests and replies under this section available
to the public, subject to the confidentiality requirements under Sec.
1206.259.
Sec. 1206.259 Does ONRR protect information I provide?
(a) Certain information you or your affiliate submit(s) to ONRR
regarding royalties on coal, including deductions and allowances, may
be exempt from disclosure.
(b) To the extent applicable laws and regulations permit, ONRR will
keep confidential any data you or your affiliate submit(s) that is
privileged, confidential, or otherwise exempt from disclosure.
(c) You and others must submit all requests for information under
the Freedom of Information Act regulations of the Department of the
Interior at 43 CFR part 2.
Sec. 1206.260 What general transportation allowance requirements
apply to me?
(a)(1) ONRR will allow a deduction for the reasonable, actual costs
to transport coal from the lease to the point off the lease or mine as
determined under Sec. 1206.261 or Sec. 1206.262, as applicable.
(2) You do not need ONRR approval before reporting a transportation
allowance for costs incurred.
(b) You may take a transportation allowance when:
(1) You value coal under Sec. 1206.252 of this part;
(2) You transport the coal from a Federal lease to a sales point,
which is remote from both the lease and mine; or
(3) You transport the coal from a Federal lease to a wash plant
when that plant is remote from both the lease and mine and, if
applicable, from the wash plant to a remote sales point.
(c) You may not take an allowance for:
(1) Transporting lease production that is not royalty-bearing;
(2) In-mine movement of your coal; or
(3) Costs to move a particular tonnage of production for which you
did not incur those costs.
(d) You only may claim a transportation allowance when you sell the
coal and pay royalties.
(e) You must allocate transportation allowances to the coal
attributed to the lease from which it was extracted.
(1) If you commingle coal produced from Federal and non-Federal
leases, you may not disproportionately allocate transportation costs to
Federal lease production. Your allocation must use the same proportion
as the ratio of the tonnage from the Federal lease production to the
tonnage from all production.
(2) If you commingle coal produced from more than one Federal
lease, you
[[Page 666]]
must allocate transportation costs to each Federal lease as
appropriate. Your allocation must use the same proportion as the ratio
of the tonnage of each Federal lease production to the tonnage of all
production.
(3) For washed coal, you must allocate the total transportation
allowance only to washed products.
(4) For unwashed coal, you may take a transportation allowance for
the total coal transported.
(5)(i) You must report your transportation costs on Form ONRR-4430
as clean coal short tons sold during the reporting period multiplied by
the sum of the per-short-ton cost of transporting the raw tonnage to
the wash plant and, if applicable, the per-short-ton cost of
transporting the clean coal tons from the wash plant to a remote sales
point.
(ii) You must determine the cost per short ton of clean coal
transported by dividing the total applicable transportation cost by the
number of clean coal tons resulting from washing the raw coal
transported.
(f) You must express transportation allowances for coal as a
dollar-value equivalent per short ton of coal transported. If you do
not base your or your affiliate's payments for transportation under a
transportation contract on a dollar-per-unit basis, you must convert
whatever consideration you or your affiliate paid to a dollar-value
equivalent.
(g) ONRR may determine your transportation allowance under Sec.
1206.254 because:
(1) There is misconduct by or between the contracting parties;
(2) ONRR determines that the consideration you or your affiliate
paid under an arm's-length transportation contract does not reflect the
reasonable cost of the transportation because you breached your duty to
market the coal for the mutual benefit of yourself and the lessor by
transporting your coal at a cost that is unreasonably high. We may
consider a transportation allowance unreasonably high if it is 10-
percent higher than the highest reasonable measures of transportation
costs including, but not limited to, transportation allowances reported
to ONRR and the cost to transport coal through the same transportation
system; or
(3) ONRR cannot determine if you properly calculated a
transportation allowance under Sec. 1206.261 or Sec. 1206.262 for any
reason including, but not limited to, your or your affiliate's failure
to provide documents that ONRR requests under 30 CFR part 1212, subpart
E.
Sec. 1206.261 How do I determine a transportation allowance if I have
an arm's-length transportation contract or no written arm's-length
contract?
(a) If you or your affiliate incur(s) transportation costs under an
arm's-length transportation contract, you may claim a transportation
allowance for the reasonable, actual costs incurred for transporting
the coal under that contract.
(b) You must be able to demonstrate that your or your affiliate's
contract is at arm's length.
(c) If you have no written contract for the arm's-length
transportation of coal, then ONRR will determine your transportation
allowance under Sec. 1206.254. You may not use this paragraph (c) if
you or your affiliate perform(s) your own transportation.
(1) You must propose to ONRR a method to determine the allowance
using the procedures in Sec. 1206.258(a).
(2) You may use that method to determine your allowance until ONRR
issues a determination.
Sec. 1206.262 How do I determine a transportation allowance for a
non-arm's-length transportation contract?
(a) This section applies if you or your affiliate do(es) not have
an arm's-length transportation contract, including situations where you
or your affiliate provide your own transportation services. You must
calculate your transportation allowance based on your or your
affiliate's reasonable, actual costs for transportation during the
reporting period using the procedures prescribed in this section.
(b) Your or your affiliate's actual costs may include:
(1) Capital costs and operating and maintenance expenses under
paragraphs (d), (e), and (f) of this section;
(2) Overhead under paragraph (g) of this section;
(3) Depreciation under paragraph (h) of this section and a return
on undepreciated capital investment under paragraph (i) of this
section, or you may elect to use a cost equal to a return on the
initial depreciable capital investment in the transportation system
under paragraph (j) of this section. After you have elected to use
either method for a transportation system, you may not later elect to
change to the other alternative without ONRR approval. If ONRR accepts
your request to change methods, you may use your changed method
beginning with the production month following the month ONRR received
your change request; and
(4) A return on the reasonable salvage value, under paragraph (i)
of this section, after you have depreciated the transportation system
to its reasonable salvage value.
(c) You may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section.
(d) Allowable capital investment costs are generally those for
depreciable fixed assets (including costs of delivery and installation
of capital equipment), which are an integral part of the transportation
system.
(e) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating
expenses that you can document.
(f) Allowable maintenance expenses include:
(1) Maintenance of the transportation system;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses
that you can document.
(g) Overhead, directly attributable and allocable to the operation
and maintenance of the transportation system, is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(h)(1) To calculate depreciation, you may elect to use either (i) a
straight-line depreciation method based on the life of the
transportation system or the life of the reserves which the
transportation system services, or (ii) a unit-of-production method.
After you make an election, you may not change methods without ONRR
approval. If ONRR accepts your request to change methods, you may use
your changed method beginning with the production month following the
month ONRR received your change request.
(2) A change in ownership of a transportation system will not alter
the depreciation schedule that the original transporter/lessee
established for purposes of the allowance calculation.
(3) You may depreciate a transportation system only once with or
without a change in ownership.
(i)(1) To calculate a return on undepreciated capital investment,
you must multiply the remaining undepreciated capital balance as of the
beginning of the period for which you
[[Page 667]]
are calculating the transportation allowance by the rate of return
provided in paragraph (k) of this section.
(2) After you have depreciated a transportation system to its
reasonable salvage value, you may continue to include in the allowance
calculation a cost equal to the reasonable salvage value multiplied by
a rate of return determined under paragraph (k) of this section.
(j) As an alternative to using depreciation and a return on
undepreciated capital investment, as provided under paragraph (b)(3) of
this section, you may use as a cost an amount equal to the allowable
initial capital investment in the transportation system multiplied by
the rate of return determined under paragraph (k) of this section. You
may not include depreciation in your allowance
(k) The rate of return is the industrial rate associated with
Standard & Poor's BBB rating.
(1) You must use the monthly average BBB rate that Standard &
Poor's publishes for the first month for which the allowance is
applicable.
(2) You must redetermine the rate at the beginning of each
subsequent calendar year.
(3) After ONRR issues a determination, you must make the
adjustments under Sec. 1206.266.
Sec. 1206.263 What are my reporting requirements under an arm's-
length transportation contract?
(a) You must use a separate entry on Form ONRR-4430 to notify ONRR
of an allowance based on transportation costs you or your affiliate
incur(s).
(b) ONRR may require you or your affiliate to submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents.
(c) You can find recordkeeping requirements in parts 1207 and 1212
of this chapter.
Sec. 1206.264 What are my reporting requirements under a non-arm's-
length transportation contract?
(a) You must use a separate entry on Form ONRR-4430 to notify ONRR
of an allowance based on non-arm's-length transportation costs you or
your affiliate incur(s).
(b)(1) For new non-arm's-length transportation facilities or
arrangements, you must base your initial deduction on estimates of
allowable transportation costs for the applicable period.
(2) You must use your or your affiliate's most recently available
operations data for the transportation system as your estimate, if
available. If such data is not available, you must use estimates based
on data for similar transportation systems.
(3) Section 1206.266 applies when you amend your report based on
the actual costs.
(c) ONRR may require you or your affiliate to submit all data used
to calculate the allowance deduction. You can find recordkeeping
requirements in parts 1207 and 1212 of this chapter.
Sec. 1206.265 What interest and penalties apply if I improperly
report a transportation allowance?
(a)(1) If ONRR determines that you took an unauthorized
transportation allowance, then you must pay any additional royalties
due, plus late payment interest calculated under Sec. 1218.202 of this
chapter.
(2) If you understated your transportation allowance, you may be
entitled to a credit without interest.
(b) If you improperly net a transportation allowance against the
sales value of the coal instead of reporting the allowance as a
separate entry on Form ONRR-4430, ONRR may assess a civil penalty under
30 CFR part 1241.
Sec. 1206.266 What reporting adjustments must I make for
transportation allowances?
(a) If your actual transportation allowance is less than the amount
you claimed on Form ONRR-4430 for each month during the allowance
reporting period, you must pay additional royalties due, plus late
payment interest calculated under Sec. 1218.202 of this chapter from
the date you took the deduction to the date you repay the difference.
(b) If the actual transportation allowance is greater than the
amount you claimed on Form ONRR-4430 for any month during the period
reported on the allowance form, you are entitled to a credit without
interest.
Sec. 1206.267 What general washing allowance requirements apply to
me?
(a)(1) If you determine the value of your coal under Sec. 1206.252
of this subpart, you may take a washing allowance for the reasonable,
actual costs to wash coal. The allowance is a deduction when
determining coal royalty value for the costs you incur to wash coal.
(2) You do not need ONRR approval before reporting a washing
allowance.
(b) You may not:
(1) Take an allowance for the costs of washing lease production
that is not royalty bearing;
(2) Disproportionately allocate washing costs to Federal leases.
You must allocate washing costs to washed coal attributable to each
Federal lease by multiplying the input ratio determined under Sec.
1206.251(e)(2)(i) by the total allowable costs.
(c)(1) You must express washing allowances for coal as a dollar-
value equivalent per short ton of coal washed.
(2) If you do not base your or your affiliate's payments for
washing under an arm's-length contract on a dollar-per-unit basis, you
must convert whatever consideration you or your affiliate paid to a
dollar-value equivalent.
(d) ONRR may determine your washing allowance under Sec. 1206.254
because:
(1) There is misconduct by or between the contracting parties;
(2) ONRR determines that the consideration you or your affiliate
paid under an arm's-length washing contract does not reflect the
reasonable cost of the washing because you breached your duty to market
the coal for the mutual benefit of yourself and the lessor by washing
your coal at a cost that is unreasonably high. We may consider a
washing allowance unreasonably high if it is 10-percent higher than the
highest other reasonable measures of washing, including but not limited
to, washing allowances reported to ONRR and costs for coal washed in
the same plant or other plants in the region; or
(3) ONRR cannot determine if you properly calculated a washing
allowance under Sec. Sec. 1206.267 through 1206.269 for any reason,
including but not limited to, your or your affiliate's failure to
provide documents that ONRR requests under 30 CFR part 1212, subpart E.
(e) You only may claim a washing allowance, when you sell the
washed coal and report and pay royalties.
Sec. 1206.268 How do I determine washing allowances if I have an
arm's-length washing contract or no written arm's-length contract?
(a) If you or your affiliate incur(s) washing costs under an arm's-
length washing contract, you may claim a washing allowance for the
reasonable, actual costs incurred.
(b) You must be able to demonstrate that your or your affiliate's
contract is arm's length.
(c) If you have no written contract for the arm's-length washing of
coal, then ONRR will determine your washing allowance under Sec.
1206.254. You may not use this paragraph (c) if you or your affiliate
perform(s) your own washing. If you or your affiliate perform(s) the
washing, then:
(1) You must propose to ONRR a method to determine the allowance
using the procedures in Sec. 1206.258(a).
[[Page 668]]
(2) You may use that method to determine your allowance until ONRR
issues a determination.
Sec. 1206.269 How do I determine washing allowances if I have a non-
arm's-length washing contract?
(a) This section applies if you or your affiliate do(es) not have
an arm's-length washing contract, including situations where you or
your affiliate provides your own washing services. You must calculate
your washing allowance based on your or your affiliate's reasonable,
actual costs for washing during the reporting period using the
procedures prescribed in this section.
(b) Your or your affiliate's actual costs can include:
(1) Capital costs and operating and maintenance expenses under
paragraphs (d), (e), and (f) of this section;
(2) Overhead under paragraph (g) of this section;
(3) Depreciation under paragraph (h) of this section and a return
on undepreciated capital investment under paragraph (i) of this
section, or you may elect to use a cost equal to a return on the
initial depreciable capital investment in the wash plant under
paragraph (j) of this section. After you have elected to use either
method for a wash plant, you may not later elect to change to the other
alternative without ONRR approval. If ONRR accepts your request to
change methods, you may use your changed method beginning with the
production month following the month ONRR received your change request;
and
(4) A return on the reasonable salvage value, under paragraph (i)
of this section, after you have depreciated the wash plant to its
reasonable salvage value.
(c) You may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section.
(d) Allowable capital investment costs are generally those for
depreciable fixed assets (including costs of delivery and installation
of capital equipment), which are an integral part of the wash plant.
(e) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating
expenses that you can document.
(f) Allowable maintenance expenses include:
(1) Maintenance of the wash plant;
(2) Maintenance of equipment; and
(3) Maintenance labor.
(4) Other directly allocable and attributable maintenance expenses
that you can document.
(g) Overhead, directly attributable and allocable to the operation
and maintenance of the wash plant, is an allowable expense. State and
Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(h)(1) To calculate depreciation, you may elect to use either a
straight-line depreciation method based on the life of the wash plant
or the life of the reserves which the wash plant services, or a unit-
of-production method. After you make an election, you may not change
methods without ONRR approval. If ONRR accepts your request to change
methods, you may use your changed method beginning with the production
month following the month ONRR received your change request.
(2) A change in ownership of a wash plant will not alter the
depreciation schedule that the original washer/lessee established for
purposes of the allowance calculation.
(3) With or without a change in ownership, you may depreciate a
wash plant only once.
(i)(1) To calculate a return on undepreciated capital investment,
you must multiply the remaining undepreciated capital balance as of the
beginning of the period for which you are calculating the washing
allowance by the rate of return provided in paragraph (k) of this
section.
(2) After you have depreciated a wash plant to its reasonable
salvage value, you may continue to include in the allowance calculation
a cost equal to the salvage value multiplied by a rate of return
determined under paragraph (k) of this section.
(j) As an alternative to using depreciation and a return on
undepreciated capital investment, as provided under paragraph (b)(3) of
this section, you may use as a cost an amount equal to the allowable
initial capital investment in the wash plant multiplied by the rate of
return as determined under paragraph (k) of this section. You may not
include depreciation in your allowance.
(k) The rate of return is the industrial rate associated with
Standard & Poor's BBB rating.
(1) You must use the monthly average BBB rate that Standard &
Poor's publishes for the first month for which the allowance is
applicable.
(2) You must redetermine the rate at the beginning of each
subsequent calendar year.
(3) After ONRR issues its determination, you must make the
adjustments under Sec. 1206.273.
Sec. 1206.270 What are my reporting requirements under an arm's-
length washing contract?
(a) You must use a separate entry on Form ONRR-4430 to notify ONRR
of an allowance based on washing costs you or your affiliate incur(s).
(b) ONRR may require you or your affiliate to submit arm's-length
washing contracts, production agreements, operating agreements, and
related documents.
(c) You can find recordkeeping requirements in parts 1207 and 1212
of this chapter.
Sec. 1206.271 What are my reporting requirements under a non-arm's-
length washing contract?
(a) You must use a separate entry on Form ONRR-4430 to notify ONRR
of an allowance based on non-arm's-length washing costs you or your
affiliate incur(s).
(b)(1) For new non-arm's-length washing facilities or arrangements,
you must base your initial deduction on estimates of allowable washing
costs for the applicable period.
(2) You must use your or your affiliate's most recently available
operations data for the wash plant as your estimate, if available. If
such data is not available, you must use estimates based on data for
similar wash plants.
(3) Section 1206.273 applies when you amend your report based on
the actual costs.
(c) ONRR may require you or your affiliate to submit all data used
to calculate the allowance deduction. You can find recordkeeping
requirements in parts 1207 and 1212 of this chapter.
Sec. 1206.272 What interest and penalties apply if I improperly
report a washing allowance?
(a)(1) If ONRR determines that you took an unauthorized washing
allowance, then you must pay any additional royalties due, plus late
payment interest calculated under Sec. 1218.202 of this chapter.
(2) If you understated your washing allowance, you may be entitled
to a credit without interest.
(b) If you improperly net a washing allowance against the sales
value of the coal instead of reporting the allowance as a separate
entry on Form ONRR-4430, ONRR may assess a civil penalty under 30 CFR
part 1241.
[[Page 669]]
Sec. 1206.273 What reporting adjustments must I make for washing
allowances?
(a) If your actual washing allowance is less than the amount you
claimed on Form ONRR-4430 for each month during the allowance reporting
period, you must pay additional royalties due, plus late payment
interest calculated under Sec. 1218.202 of this chapter from the date
you took the deduction to the date you repay the difference.
(b) If the actual washing allowance is greater than the amount you
claimed on Form ONRR-4430 for any month during the period reported on
the allowance form, you are entitled to a credit without interest.
0
9. Revise subpart J to read as follows:
Subpart J--Indian Coal
Sec.
1206.450 What is the purpose and scope of this subpart?
1206.451 How do I determine royalty quantity and quality?
1206.452 How do I calculate royalty value for coal I or my affiliate
sell(s) under an arm's-length or non-arm's-length contract?
1206.453 How will ONRR determine if my royalty payments are correct?
1206.454 How will ONRR determine the value of my coal for royalty
purposes?
1206.455 What records must I keep to support my calculations of
royalty under this subpart?
1206.456 What are my responsibilities to place production into
marketable condition and to market production?
1206.457 When is an ONRR audit, review, reconciliation, monitoring,
or other like process considered final?
1206.458 How do I request a valuation determination or guidance?
1206.459 Does ONRR protect information I provide?
1206.460 What general transportation allowance requirements apply to
me?
1206.461 How do I determine a transportation allowance if I have an
arm's-length transportation contract or no written arm's-length
contract?
1206.462 How do I determine a transportation allowance if I have a
non-arm's-length transportation contract?
1206.463 What are my reporting requirements under an arm's-length
transportation contract?
1206.464 What are my reporting requirements under a non-arm's-length
transportation contract or no written arm's-length contract?
1206.465 What interest and penalties apply if I improperly report a
transportation allowance?
1206.466 What reporting adjustments must I make for transportation
allowances?
1206.467 What general washing allowance requirements regarding apply
to me?
1206.468 How do I determine a washing allowance if I have an arm's-
length washing contract or no written arm's-length contract?
1206.469 How do I determine a washing allowance if I have a non-
arm's-length washing contract?
1206.470 What are my reporting requirements under an arm's-length
washing contract?
1206.471 What are my reporting requirements under a non-arm's-length
washing contract or no written arm's-length contract?
1206.472 What interest and penalties apply if I improperly report a
washing allowance?
1206.473 What reporting adjustments must I make for washing
allowances?
Subpart J--Indian Coal
Sec. 1206.450 What is the purpose and scope of this subpart?
(a) This subpart applies to all coal produced from Indian tribal
coal leases and coal leases on land held by individual Indian mineral
owners. It explains how you, as the lessee, must calculate the value of
production for royalty purposes consistent with the mineral leasing
laws, other applicable laws, and lease terms (except leases on the
Osage Indian Reservation, Osage County, Oklahoma).
(b) The terms ``you'' and ``your'' in this subpart refer to the
lessee.
(c) If the regulations in this subpart are inconsistent with:
(1) A Federal statute or treaty;
(2) A settlement agreement;
(3) A written agreement between the lessee and the ONRR Director
establishing a method to determine the value of production from any
lease that ONRR expects, at least, would approximate the value
established under this subpart; or
(4) An express provision of a coal lease subject to this subpart,
then the statute, settlement agreement, written agreement, or lease
provision will govern to the extent of the inconsistency.
(d) ONRR may audit and order you to adjust all royalty payments.
(e) The regulations in this subpart, intended to ensure that the
trust responsibilities of the United States with respect to the
administration of Indian coal leases, are discharged under the
requirements of the governing mineral leasing laws, treaties, and lease
terms.
Sec. 1206.451 How do I determine royalty quantity and quality?
(a) You must calculate royalties based on the quantity and quality
of coal at the royalty measurement point that ONRR and BLM jointly
determine.
(b) You must measure coal in short tons using the methods BLM
prescribes for Indian coal leases. You must report coal quantity on
appropriate forms required in 30 CFR part 1210.
(c)(1) You are not required to pay royalties on coal you produce
and add to stockpiles or inventory until you use, sell, or otherwise
finally dispose of such coal.
(2) ONRR may request BLM to require you to increase your lease bond
if BLM determines that stockpiles or inventory are excessive such that
they increase the risk of resource degradation.
(d) You must pay royalty at the rate specified in your lease at the
time you use, sell, or otherwise finally dispose of the coal.
(e) You must allocate washed coal by attributing the washed coal to
the leases from which it was extracted.
(1) If the wash plant washes coal from only one lease, the quantity
of washed coal allocable to the lease is the total output of washed
coal from the plant.
(2) If the wash plant washes coal from more than one lease, you
must determine the tonnage of washed coal attributable to each lease
by:
(i) First, calculating the input ratio of washed coal allocable to
each lease by dividing the tonnage of coal you input to the wash plant
from each lease by the total tonnage of coal input to the wash plant
from all leases; and
(ii) Then multiplying the input ratio derived under paragraph
(e)(2)(i) of this section by the tonnage of total output of washed coal
from the plant.
Sec. 1206.452 How do I calculate royalty value for coal I or my
affiliate sell(s) under an arm's-length or non-arm's-length contract?
(a) The value of coal under this section for royalty purposes is
the gross proceeds accruing to you or your affiliate under the first
arm's-length contract less an applicable transportation allowance
determined under Sec. Sec. 1206.460 through 1206.462 and washing
allowance under Sec. Sec. 1206.467 through 1206.469. You must use this
paragraph (a) to value coal when:
(1) You sell under an arm's-length contract; or
(2) You sell or transfer to your affiliate or another person under
a non-arm's-length contract, and that affiliate or person, or another
affiliate of either of them, then sells the coal under an arm's-length
contract.
(b) If you have no contract for the sale of coal subject to this
section because you or your affiliate used the coal in a power plant
you or your affiliate own(s) for the generation and sale of electricity
and;
(1) You or your affiliate sell(s) the electricity, then the value
of the coal subject to this section, for royalty purposes, is the gross
proceeds accruing to you for the power plant's arm's-
[[Page 670]]
length sales of the electricity less applicable transportation and
washing deductions determined under Sec. Sec. 1206.460 through
1206.462 and Sec. Sec. 1206.467 through 1206.469 of this subpart and,
if applicable, transmission and generation deductions determined under
Sec. Sec. 1206.353 and 1206.352 of subpart H;
(2) You or your affiliate do(es) not sell the electricity at arm's
length (i.e. you or your affiliate deliver(s) the electricity directly
to the grid), then ONRR will determine the value of the coal under
Sec. 1206.454.
(i) You must propose to ONRR a method to determine the value using
the procedures in Sec. 1206.458(a).
(ii) You may use that method to determine value, for royalty
purposes, until ONRR issues a determination.
(iii) After ONRR issues a determination, you must make the
adjustments under Sec. 1206.453(a)(2).
(c) If you are a coal cooperative, or a member of a coal
cooperative, and;
(1) You sell or transfer coal to another member of the coal
cooperative, and that member of the coal cooperative then sells the
coal under an arm's-length contract, then you must value the coal under
paragraph (a) of this section; or
(2) You sell or transfer coal to another member of the coal
cooperative, and the coal is used by you, the coal cooperative, or
another member of the coal cooperative, in a power plant for the
generation and sale of electricity, then you must value the coal under
paragraph (b) of this section.
(d) If you are entitled to take a washing allowance and
transportation allowance for royalty purposes under this section, under
no circumstances may the washing allowance plus the transportation
allowance reduce the royalty value of the coal to zero.
(e) The values in this section do not apply, if ONRR decides to
value your coal under Sec. 1206.454.
Sec. 1206.453 How will ONRR determine if my royalty payments are
correct?
(a)(1) ONRR may monitor, review, and audit the royalties you
report. If ONRR determines that your reported value is inconsistent
with the requirements of this subpart, ONRR will direct you to use a
different measure of royalty value, or decide your value, under Sec.
1206.454.
(2) If ONRR directs you to use a different royalty value, you must
either pay any underpaid royalties plus late payment interest
calculated under Sec. 1218.202 of this chapter or report a credit for,
or request a refund of, any overpaid royalties.
(b) When the provisions in this subpart refer to gross proceeds, in
conducting reviews and audits, ONRR will examine if your or your
affiliate's contract reflects the total consideration actually
transferred, either directly or indirectly, from the buyer to you or
your affiliate for the coal. If ONRR determines that a contract does
not reflect the total consideration, ONRR may decide your value under
Sec. 1206.454.
(c) ONRR may decide to value your coal under Sec. 1206.454, if
ONRR determines that the gross proceeds accruing to you or your
affiliate under a contract do not reflect reasonable consideration
because:
(1) There is misconduct by or between the contracting parties;
(2) You breached your duty to market the coal for the mutual
benefit of yourself and the lessor by selling your coal at a value that
is unreasonably low. ONRR may consider a sales price unreasonably low,
if it is 10-percent less than the lowest other reasonable measures of
market price, including but not limited to, prices reported to ONRR for
like-quality coal; or
(3) ONRR cannot determine if you properly valued your coal under
Sec. 1206.452 for any reason, including but not limited to, your or
your affiliate's failure to provide documents to ONRR under 30 CFR part
1212, subpart E.
(d) You have the burden of demonstrating that your or your
affiliate's contract is arm's length.
(e) ONRR may require you to certify that the provisions in your or
your affiliate's contract include(s) all of the consideration the buyer
paid you or your affiliate, either directly or indirectly, for the
coal.
(f)(1) Absent contract revision or amendment, if you or your
affiliate fail(s) to take proper or timely action to receive prices or
benefits to which you or your affiliate are entitled, you must pay
royalty based upon that obtainable price or benefit.
(2) If you or your affiliate make timely application for a price
increase or benefit allowed under your or your affiliate's contract,
but the purchaser refuses, and you or your affiliate take reasonable
documented measures to force purchaser compliance, you will not owe
additional royalties unless or until you or your affiliate receive
additional monies or consideration resulting from the price increase.
You may not construe this paragraph to permit you to avoid your royalty
payment obligation in situations where a purchaser fails to pay, in
whole or in part, or timely, for a quantity of coal.
(g)(1) You or your affiliate must make all contracts, contract
revisions, or amendments in writing, and all parties to the contract
must sign the contract, contract revisions, or amendments.
(2) If you or your affiliate fail(s) to comply with paragraph
(g)(1) of this section, ONRR may decide to value your coal under Sec.
1206.454.
(3) This provision applies notwithstanding any other provisions in
this title 30 to the contrary.
Sec. 1206.454 How will ONRR determine the value of my coal for
royalty purposes?
If ONRR decides to value your coal for royalty purposes under Sec.
1206.454, or any other provision in this subpart, then ONRR will
determine value by considering any information we deem relevant, which
may include, but is not limited to:
(a) The value of like-quality coal from the same mine, nearby
mines, same region, or other regions, or washed in the same or nearby
wash plant;
(b) Public sources of price or market information that ONRR deems
reliable, including but not limited to, the price of electricity;
(c) Information available to ONRR and information reported to it,
including but not limited to, on Form ONRR-4430;
(d) Costs of transportation or washing, if ONRR determines they are
applicable; or
(e) Any other information ONRR deems relevant regarding the
particular lease operation or the salability of the coal.
Sec. 1206.455 What records must I keep to support my calculations of
royalty under this subpart?
If you value your coal under this subpart, you must retain all data
relevant to the determination of the royalty you paid. You can find
recordkeeping requirements in parts 1207 and 1212 of this chapter.
(a) You must show:
(1) How you calculated the royalty value, including all allowable
deductions; and
(2) How you complied with this subpart.
(b) Upon request, you must submit all data to ONRR or the
representative of the Indian lessor, or to the Inspector General of the
Department of the Interior or other persons authorized to receive such
information. Such data may include arm's-length sales and sales
quantity data for like-quality coal sold, purchased, or otherwise
obtained by you or your affiliate from the same mine, nearby mines,
same region, or other regions. You must comply with any such
requirement within the time ONRR specifies.
[[Page 671]]
Sec. 1206.456 What are my responsibilities to place production into
marketable condition and to market production?
(a) You must place coal in marketable condition and market the coal
for the mutual benefit of the lessee and the lessor at no cost to the
Indian lessor.
(b) If you use gross proceeds under an arm's-length contract to
determine royalty, you must increase those gross proceeds to the extent
that the purchaser, or any other person, provides certain services that
you normally are responsible to perform to place the coal in marketable
condition or to market the coal.
Sec. 1206.457 When is an ONRR audit, review, reconciliation,
monitoring, or other like process considered final?
Notwithstanding any provision in these regulations to the contrary,
ONRR will not consider any audit, review, reconciliation, monitoring,
or other like process that results in ONRR redetermining royalty due,
under this subpart, final or binding as against the Federal Government
or its beneficiaries unless ONRR chooses to formally close the audit
period in writing.
Sec. 1206.458 How do I request a valuation determination or guidance?
(a) You may request a valuation determination or guidance from ONRR
regarding any coal produced. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, all interest owners
of those leases, and the operator(s) for those leases;
(3) Completely explain all relevant facts. You must inform ONRR of
any changes to relevant facts that occur before we respond to your
request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to
all relevant precedents (including adverse precedents); and
(6) Suggest a proposed valuation method.
(b) In response to your request, ONRR may:
(1) Request that the Assistant Secretary for Policy, Management and
Budget issue a determination; or
(2) Decide that ONRR will issue guidance; or
(3) Inform you in writing that ONRR will not provide a
determination or guidance. Situations in which ONRR typically will not
provide any determination or guidance include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or
administrative appeals.
(c)(1) A determination the Assistant Secretary for Policy,
Management and Budget signs is binding on both you and ONRR until the
Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a determination, you must
make any adjustments in royalty payments that follow from the
determination and, if you owe additional royalties, you must pay any
additional royalties due, plus late payment interest calculated under
Sec. 1218.202 of this chapter.
(3) A determination the Assistant Secretary signs is the final
action of the Department and is subject to judicial review under 5
U.S.C. 701-706.
(d) Guidance ONRR issues is not binding on ONRR, Tribes, individual
Indian mineral owners, or you with respect to the specific situation
addressed in the guidance.
(1) Guidance and ONRR's decision whether or not to issue guidance
or request an Assistant Secretary determination, or neither, under
paragraph (b) of this section, are not appealable decisions or orders
under 30 CFR part 1290.
(2) If you receive an order requiring you to pay royalty on the
same basis as the guidance, you may appeal that order under 30 CFR part
1290.
(e) ONRR or the Assistant Secretary may use any of the applicable
criteria in this subpart to provide guidance or make a determination.
(f) A change in an applicable statute or regulation on which ONRR
based any guidance, or the Assistant Secretary based any determination,
takes precedence over the determination or guidance after the effective
date of the statute or regulation, regardless of whether ONRR or the
Assistant Secretary modifies or rescinds the guidance or determination.
(g) ONRR may make requests and replies under this section available
to the public, subject to the confidentiality requirements under Sec.
1206.459.
Sec. 1206.459 Does ONRR protect information I provide?
(a) Certain information you or your affiliate submit(s) to ONRR
regarding royalties on coal, including deductions and allowances, may
be exempt from disclosure.
(b) To the extent applicable laws and regulations permit, ONRR will
keep confidential any data you or your affiliate submit(s) that is
privileged, confidential, or otherwise exempt from disclosure.
(c) You and others must submit all requests for information under
the Freedom of Information Act regulations of the Department of the
Interior at 43 CFR part 2.
Sec. 1206.460 What general transportation allowance requirements
apply to me?
(a)(1) ONRR will allow a deduction for the reasonable, actual costs
to transport coal from the lease to the point off the lease or mine as
determined under Sec. 1206.461 or Sec. 1206.462, as applicable.
(2) Before you may take any transportation allowance, you must
submit a completed page 1 of Form ONRR-4293, Coal Transportation
Allowance Report, under sections Sec. 1206.463 and Sec. 1206.464 of
this subpart. You may claim a transportation allowance retroactively
for a period of not more than 3 months prior to the first day of the
month that ONRR receives your Form ONRR-4293.
(3) You may not use a transportation allowance that was in effect
before [EFFECTIVE DATE OF THE FINAL RULE]. You must use the provisions
of this subpart to determine your transportation allowance.
(b) You may take a transportation allowance when:
(1) You value coal under Sec. 1206.452 of this part;
(2) You transport the coal from an Indian lease to a sales point
which, is remote from both the lease and mine; or
(3) You transport the coal from an Indian lease to a wash plant
when that plant is remote from both the lease and mine and, if
applicable, from the wash plant to a remote sales point.
(c) You may not take an allowance for:
(1) Transporting lease production that is not royalty-bearing;
(2) In-mine movement of your coal; or
(3) Costs to move a particular tonnage of production for which you
did not incur those costs.
(d) You only may claim a transportation allowance when you sell the
coal and pay royalties.
(e) You must allocate transportation allowances to the coal
attributed to the lease from which it was extracted.
(1) If you commingle coal produced from Indian and non-Indian
leases, you may not disproportionately allocate transportation costs to
Indian lease production. Your allocation must use the same proportion
as the ratio of the tonnage from the Indian lease production to the
tonnage from all production.
(2) If you commingle coal produced from more than one Indian lease,
you must allocate transportation costs to each Indian lease as
appropriate. Your allocation must use the same proportion as the ratio
of the tonnage of each Indian
[[Page 672]]
leases production to the tonnage of all production.
(3) For washed coal, you must allocate the total transportation
allowance only to washed products.
(4) For unwashed coal, you may take a transportation allowance for
the total coal transported.
(5)(i) You must report your transportation costs on Form ONRR-4430
as clean coal short tons sold during the reporting period multiplied by
the sum of the per short-ton cost of transporting the raw tonnage to
the wash plant and, if applicable, the per short-ton cost of
transporting the clean coal tons from the wash plant to a remote sales
point.
(ii) You must determine the cost per short ton of clean coal
transported by dividing the total applicable transportation cost by the
number of clean coal tons resulting from washing the raw coal
transported.
(f) You must express transportation allowances for coal as a
dollar-value equivalent per short ton of coal transported. If you do
not base your or your affiliate's payments for transportation under a
transportation contract on a dollar-per-unit basis, you must convert
whatever consideration you or your affiliate paid to a dollar-value
equivalent.
(g) ONRR may determine your transportation allowance under Sec.
1206.454 because:
(1) There is misconduct by or between the contracting parties;
(2) ONRR determines that the consideration you or your affiliate
paid under an arm's-length transportation contract does not reflect the
reasonable cost of the transportation because you breached your duty to
market the coal for the mutual benefit of yourself and the lessor by
transporting your coal at a cost that is unreasonably high. We may
consider a transportation allowance unreasonably high if it is 10-
percent higher than the highest reasonable measures of transportation
costs including, but not limited to, transportation allowances reported
to ONRR and the cost to transport coal through the same transportation
system; or
(3) ONRR cannot determine if you properly calculated a
transportation allowance under Sec. 1206.461 or Sec. 1206.462 for any
reason including, but not limited to, your or your affiliate's failure
to provide documents that ONRR requests under 30 CFR part 1212, subpart
E.
Sec. 1206.461 How do I determine a transportation allowance if I have
an arm's-length transportation contract or no written arm's-length
contract?
(a) If you or your affiliate incur(s) transportation costs under an
arm's-length transportation contract, you may claim a transportation
allowance for the reasonable, actual costs incurred for transporting
the coal under that contract.
(b) You must be able to demonstrate that your or your affiliate's
contract is at arm's length.
(c) If you have no written contract for the arm's-length
transportation of coal, then ONRR will determine your transportation
allowance under Sec. 1206.454. You may not use this paragraph (c) if
you or your affiliate perform(s) your own transportation.
(1) You must propose to ONRR a method to determine the allowance
using the procedures in Sec. 1206.458(a).
(2) You may use that method to determine your allowance until ONRR
issues a determination.
Sec. 1206.462 How do I determine a transportation allowance if I have
a non-arm's-length transportation contract?
(a) This section applies if you or your affiliate do(es) not have
an arm's-length transportation contract, including situations where you
or your affiliate provide your own transportation services. Calculate
your transportation allowance based on your or your affiliate's
reasonable, actual costs for transportation during the reporting period
using the procedures prescribed in this section.
(b) Your or your affiliate's actual costs may include:
(1) Capital costs and operating and maintenance expenses under
paragraphs (d), (e), and (f) of this section;
(2) Overhead under paragraph (g) of this section; and
(3) Depreciation under paragraph (h) of this section and a return
on undepreciated capital investment under paragraph (i) of this
section, or you may elect to use a cost equal to a return on the
initial depreciable capital investment in the transportation system
under paragraph (j) of this section. After you have elected to use
either method for a transportation system, you may not later elect to
change to the other alternative without ONRR approval. If ONRR accepts
your request to change methods, you may use your changed method
beginning with the production month following the month ONRR received
your change request.
(c) You may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section.
(d) Allowable capital investment costs are generally those for
depreciable fixed assets (including costs of delivery and installation
of capital equipment) which are an integral part of the transportation
system.
(e) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating expense
that you can document.
(f) Allowable maintenance expenses include:
(1) Maintenance of the transportation system;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses
that you can document.
(g) Overhead, directly attributable and allocable to the operation
and maintenance of the transportation system, is an allowable expense.
State and Federal income taxes and Indian tribal severance taxes and
other fees, including royalties, are not allowable expenses.
(h)(1) To calculate depreciation, you may elect to use either a
straight-line depreciation method based on the life of the
transportation system or the life of the reserves which the
transportation system services, or a unit-of-production method. After
you make an election, you may not change methods without ONRR approval.
If ONRR accepts your request to change methods, you may use your
changed method beginning with the production month following the month
ONRR received your change request.
(2) A change in ownership of a transportation system will not alter
the depreciation schedule the original transporter/lessee established
for purposes of the allowance calculation.
(3) You may depreciate a transportation system only once with or
without a change in ownership.
(i) To calculate a return on undepreciated capital investment,
multiply the remaining undepreciated capital balance as of the
beginning of the period for which you are calculating the
transportation allowance by the rate of return provided in paragraph
(k) of this section.
(j) As an alternative to using depreciation and a return on
[[Page 673]]
undepreciated capital investment, as provided under paragraph (b)(3) of
this section, you may use as a cost an amount equal to the allowable
initial capital investment in the transportation system multiplied by
the rate of return determined under paragraph (k) of this section. You
may not include depreciation in your allowance.
(k) The rate of return is the industrial rate associated with
Standard & Poor's BBB rating.
(1) You must use the monthly average BBB rate that Standard &
Poor's publishes for the first month for which the allowance is
applicable.
(2) You must redetermine the rate at the beginning of each
subsequent calendar year.
(3) After ONRR issues a determination, you must make the
adjustments under Sec. 1206.466.
Sec. 1206.463 What are my reporting requirements under an arm's-
length transportation contract?
(a) You must use a separate entry on Form ONRR-4430 to notify ONRR
of an allowance based on transportation costs you or your affiliate
incur(s).
(b) ONRR may require you or your affiliate to submit arm's-length
transportation contracts, production agreements, operating agreements,
and related documents.
(c) You can find recordkeeping requirements in parts 1207 and 1212
of this chapter.
(d)(1) You must submit page 1 of the initial Form ONRR-4293 prior
to, or at the same time as, you report the transportation allowance
determined under an arm's-length contract on Form ONRR-4430.
(2) The initial Form ONRR-4293 is effective beginning with the
production month that you are first authorized to deduct a
transportation allowance and continues until the end of the calendar
year, or until the termination, modification, or amendment of the
applicable contract or rate, whichever is earlier.
(3) After the initial period that ONRR first authorized you to
deduct a transportation allowance and for succeeding periods, you must
submit the entire Form ONRR-4293 by the earlier of:
(i) Within 3 months after the end of the calendar year; or
(ii) After the termination, modification, or amendment of the
applicable contract or rate.
(4) You may request to use an allowance for a longer period than
that required under paragraph (d)(2) of this section.
(i) You may use that allowance beginning with the production month
following the month ONRR received your request to use the allowance for
a longer period until ONRR decides whether to approve the longer
period.
(ii) ONRR's decision whether or not to approve a longer period is
not appealable under 30 CFR part 1290.
(iii) If ONRR does not approve the longer period, you must adjust
your transportation allowance under Sec. 1206.466.
Sec. 1206.464 What are my reporting requirements under a non-arm's-
length transportation contract or no written arm's-length contract?
(a) You must use a separate entry on Form ONRR-4430 to notify ONRR
of an allowance based on non-arm's-length transportation costs you or
your affiliate incur(s).
(b) ONRR may require you or your affiliate to submit all data used
to calculate the allowance deduction. You can find recordkeeping
requirements in parts 1207 and 1212 of this chapter.
(c)(1) You must submit an initial Form ONRR-4293 prior to, or at
the same time as, the transportation allowance determined under a non-
arm's-length contract or no written arm's-length contract situation
that you report on Form ONRR-4430. If ONRR receives a Form ONRR-4293 by
the end of the month that the Form ONRR-4430 is due, ONRR will consider
the form timely received. You may base the initial form on estimated
costs.
(2) The initial Form ONRR-4293 is effective beginning with the
production month that you are first authorized to deduct a
transportation allowance and continues until the end of the calendar
year or termination, modification, or amendment of the applicable
contract or rate, whichever is earlier.
(3)(i) At the end of the calendar-year for which you submitted a
Form ONRR-4293 based on estimates, you must submit another completed
Form ONRR-4293 containing the actual costs for that calendar year.
(ii) If the transportation continues, you must include on Form
ONRR-4293 your estimated costs for the next calendar year.
(A) You must base the estimated transportation allowance on the
actual costs for the previous reporting period plus or minus any
adjustments based on your knowledge of decreases or increases that will
affect the allowance.
(B) ONRR must receive Form ONRR-4293 within 3 months after the end
of the previous calendar year.
(d)(1) For new non-arm's-length transportation facilities or
arrangements, on your initial Form ONRR-4293, you must include
estimates of the allowable transportation costs for the applicable
period.
(2) You must use your or your affiliate's most recently available
operations data for the transportation system as your estimate, if
available. If such data is not available, you must use estimates based
on data for similar transportation systems.
(e) Upon ONRR's request, you must submit all data used to prepare
your Form ONRR-4293. You must provide the data within a reasonable
period of time, as ONRR determines.
(f) Section 1206.466 applies when you amend your Form ONRR-4293
based on the actual costs.
Sec. 1206.465 What interest and penalties apply if I improperly
report a transportation allowance?
(a)(1) If ONRR determines that you took an unauthorized
transportation allowance, then you must pay any additional royalties
due, plus late payment interest calculated under Sec. 1218.202 of this
chapter.
(2) If you understated your transportation allowance, you may be
entitled to a credit without interest.
(b) If you improperly net a transportation allowance against the
sales value of the coal instead of reporting the allowance as a
separate entry on Form ONRR-4430, ONRR may assess a civil penalty under
30 CFR part 1241.
Sec. 1206.466 What reporting adjustments must I make for
transportation allowances?
(a) If your actual transportation allowance is less than the amount
you claimed on Form ONRR-4430 for each month during the allowance
reporting period, you must pay additional royalties due, plus late
payment interest calculated under Sec. 1218.202 of this chapter from
the date you took the deduction to the date you repay the difference.
(b) If the actual transportation allowance is greater than the
amount you claimed on Form ONRR-4430 for any month during the period
reported on the allowance form, you are entitled to a credit without
interest.
Sec. 1206.467 What general washing allowance requirements apply to
me?
(a)(1) If you determine the value of your coal under Sec. 1206.452
of this subpart, you may take a washing allowance for the reasonable,
actual costs to wash coal. The allowance is a deduction when
determining coal royalty value for the costs you incur to wash coal.
(2) Before you may take any deduction, you must submit a completed
page one of Form ONRR-
[[Page 674]]
4292, Coal Washing Allowance Report, under Sec. Sec. 1206.470 and
1206.471 of this subpart. You may claim a washing allowance
retroactively for a period of not more than 3 months prior to the first
day of the month that you have filed Form ONRR-4292 with ONRR.
(3) You may not use a washing allowance that was in effect before
the effective date of the final rule. You must use the provisions of
this subpart to determine your washing allowance.
(b) You may not:
(1) Take an allowance for the costs of washing lease production
that is not royalty bearing;
(2) Disproportionately allocate washing costs to Indian leases. You
must allocate washing costs to washed coal attributable to each Indian
lease by multiplying the input ratio determined under Sec.
1206.451(e)(2)(i) by the total allowable costs.
(c)(1) You must express washing allowances for coal as a dollar-
value equivalent per short ton of coal washed.
(2) If you do not base your or your affiliate's payments for
washing under an arm's-length contract on a dollar-per-unit basis, you
must convert whatever consideration you or your affiliate paid to a
dollar-value equivalent.
(d) ONRR may determine your washing allowance under Sec. 1206.454
because:
(1) There is misconduct by or between the contracting parties;
(2) ONRR determines that the consideration you or your affiliate
paid under an arm's-length washing contract does not reflect the
reasonable cost of the washing because you breached your duty to market
the coal for the mutual benefit of yourself and the lessor by washing
your coal at a cost that is unreasonably high. We may consider a
washing allowance unreasonably high if it is 10-percent higher than the
highest other reasonable measures of washing, including but not limited
to, washing allowances reported to ONRR and costs for coal washed in
the same plant or other plants in the region; or
(3) ONRR cannot determine if you properly calculated a washing
allowance under Sec. Sec. 1206.467 through 1206.469 for any reason,
including but not limited to, your or your affiliate's failure to
provide documents that ONRR requests under 30 CFR part 1212, subpart E.
(e) You only may claim a washing allowance, if you sell the washed
coal and report and pay royalties.
Sec. 1206.468 How do I determine a washing allowance if I have an
arm's-length washing contract or no written arm's-length contract?
(a) If you or your affiliate incur(s) washing costs under an arm's-
length washing contract, you may claim a washing allowance for the
reasonable, actual costs incurred.
(b) You must be able to demonstrate that your or your affiliate's
contract is arm's length.
(c) If you have no contract for the washing of coal, then ONRR will
determine your transportation allowance under Sec. 1206.454. You may
not use this paragraph (c), if you or your affiliate perform(s) your
own washing. If you or your affiliate perform(s) the washing, then:
(1) You must propose to ONRR a method to determine the allowance
using the procedures in Sec. 1206.458(a).
(2) You may use that method to determine your allowance until ONRR
issues a determination.
Sec. 1206.469 How do I determine a washing allowance if I have a non-
arm's-length washing contract?
(a) This section applies if you or your affiliate do(es) not have
an arm's-length washing contract, including situations where you or
your affiliate provides your own washing services. Calculate your
washing allowance based on your or your affiliate's reasonable, actual
costs for washing during the reporting period using the procedures
prescribed in this section.
(b) Your or your affiliate's actual costs may include:
(1) Capital costs and operating and maintenance expenses under
paragraphs (d), (e), and (f) of this section;
(2) Overhead under paragraph (g) of this section; and
(3) Depreciation under paragraph (h) of this section and a return
on undepreciated capital investment under paragraph (i) of this
section, or a cost equal to a return on the initial depreciable capital
investment in the wash plant under paragraph (j) of this section. After
you have elected to use either method for a wash plant, you may not
later elect to change to the other alternative without ONRR approval.
If ONRR accepts your request to change methods, you may use your
changed method beginning with the production month following the month
ONRR received your change request.
(c) You may not use any cost as a deduction that duplicates all or
part of any other cost that you use under this section.
(d) Allowable capital investment costs are generally those for
depreciable fixed assets (including costs of delivery and installation
of capital equipment), which are an integral part of the wash plant.
(e) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating
expenses that you can document.
(f) Allowable maintenance expenses include:
(1) Maintenance of the wash plant;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses
that you can document.
(g) Overhead, directly attributable and allocable to the operation
and maintenance of the wash plant is an allowable expense. State and
Federal income taxes and Indian tribal severance taxes and other fees,
including royalties, are not allowable expenses.
(h)(1) To calculate depreciation, you may elect to use either (i) a
straight-line depreciation method based on the life of the wash plant
or the life of the reserves which the wash plant services, or (ii) a
unit-of-production method. After you make an election, you may not
change methods without ONRR approval. If ONRR accepts your request to
change methods, you may use your changed method beginning with the
production month following the month ONRR received your change request.
(2) A change in ownership of a wash plant will not alter the
depreciation schedule the original washer/lessee established for
purposes of the allowance calculation.
(3) With or without a change in ownership, you may depreciate a
wash plant only once.
(i) To calculate a return on undepreciated capital investment,
multiply the remaining undepreciated capital balance as of the
beginning of the period for which you are calculating the washing
allowance by the rate of return provided in paragraph (k) of this
section.
(j) As an alternative to using depreciation and a return on
undepreciated capital investment, as provided under paragraph (b)(3) of
this section, you may use as a cost an amount equal to the allowable
initial
[[Page 675]]
capital investment in the wash plant multiplied by the rate of return
as determined under paragraph (k) of this section. You may not include
depreciation in your allowance.
(k) The rate of return is the industrial rate associated with
Standard & Poor's BBB rating.
(1) You must use the monthly average BBB rate that Standard &
Poor's publishes for the first month for which the allowance is
applicable.
(2) You must redetermine the rate at the beginning of each
subsequent calendar year.
(3) After ONRR issues its determination, you must make the
adjustments under Sec. 1206.473.
Sec. 1206.470 What are my reporting requirements under an arm's-
length washing contract?
(a) You must use a separate entry on Form ONRR-4430 to notify ONRR
of an allowance based on washing costs you or your affiliate incur(s).
(b) ONRR may require you or your affiliate to submit arm's-length
washing contracts, production agreements, operating agreements, and
related documents.
(c) You can find recordkeeping requirements in parts 1207 and 1212
of this chapter.
(d)(1) You must file an initial Form ONRR-4292 prior to, or at the
same time, as the washing allowance determined under an arm's-length
contract or no written arm's-length contract situation that you report
on Form ONRR-4430. If ONRR receives a Form ONRR-4292 by the end of the
month that the Form ONRR-4430 is due, ONRR will consider the form
timely received.
(2) The initial Form ONRR-4292 is effective beginning with the
production month that you are first authorized to deduct a washing
allowance and continues until the end of the calendar year, or until
the termination, modification, or amendment of the applicable contract
or rate, whichever is earlier.
(3) After the initial period that ONRR first authorized you to
deduct a washing allowance, and for succeeding periods, you must submit
the entire Form ONRR-4292 by the earlier of:
(i) Within 3 months after the end of the calendar year; or
(ii) After the termination, modification, or amendment of the
applicable contract or rate.
(4) You may request to use an allowance for a longer period than
that required under paragraph (d)(2) of this section.
(i) You may use that allowance beginning with the production month
following the month ONRR received your request to use the allowance for
a longer period until ONRR decides whether to approve the longer
period.
(ii) ONRR's decision whether or not to approve a longer period is
not appealable under 30 CFR part 1290.
(iii) If ONRR does not approve the longer period, you must adjust
your transportation allowance under Sec. 1206.466.
Sec. 1206.471 What are my reporting requirements under a non-arm's-
length washing contract or no written arm's-length contract?
(a) You must use a separate entry on Form ONRR-4430 to notify ONRR
of an allowance based on non-arm's-length washing costs you or your
affiliate incur(s).
(b) ONRR may require you or your affiliate to submit all data used
to calculate the allowance deduction. You can find recordkeeping
requirements in parts 1207 and 1212 of this chapter.
(c)(1) You must submit an initial Form ONRR-4292 prior to, or at
the same time as, the washing allowance determined under a non-arm's-
length contract or no written arm's-length contract situation that you
report on Form ONRR-4430. If ONRR receives a Form ONRR-4292 by the end
of the month that the Form ONRR-4430 is due, ONRR will consider the
form received timely. You may base the initial reporting on estimated
costs.
(2) The initial Form ONRR-4292 is effective beginning with the
production month that you are first authorized to deduct a washing
allowance and continues until the end of the calendar year or
termination, modification, or amendment of the applicable contract or
rate, whichever is earlier.
(3)(i) At the end of the calendar year for which you submitted a
Form ONRR-4292, you must submit another completed Form ONRR-4292
containing the actual costs for that calendar year.
(ii) If coal washing continues, you must include on Form ONRR-4292
your estimated costs for the next calendar year.
(A) You must base the estimated coal washing allowance on the
actual costs for the previous period plus or minus any adjustments
based on your knowledge of decreases or increases that will affect the
allowance.
(B) ONRR must receive Form ONRR-4292 within 3 months after the end
of the previous calendar year.
(d)(1) For new non-arm's-length washing facilities or arrangements
on your initial Form ONRR-4292, you must include estimates of allowable
washing costs for the applicable period.
(2) You must use your or your affiliate's most recently available
operations data for the wash plant as your estimate, if available. If
such data is not available, you must use estimates based on data for
similar wash plants.
(e) Upon ONRR's request, you must submit all data you used to
prepare your Forms ONRR-4293. You must provide the data within a
reasonable period of time, as ONRR determines.
(f) Section 1206.472 applies when you amend your Form ONRR-4292
based on the actual costs.
Sec. 1206.472 What interest and penalties apply if I improperly
report a washing allowance?
(a)(1) If ONRR determines that you took an unauthorized washing
allowance, then you must pay any additional royalties due, plus late
payment interest calculated under Sec. 1218.202 of this chapter.
(2) If you understated your washing allowance, you may be entitled
to a credit without interest.
(b) If you improperly net a washing allowance against the sales
value of the coal instead of reporting the allowance as a separate
entry on Form ONRR-4430, ONRR may assess a civil penalty under 30 CFR
part 1241.
Sec. 1206.473 What reporting adjustments must I make for washing
allowances?
(a) If your actual washing allowance is less than the amount you
claimed on Form ONRR-4430 for each month during the allowance reporting
period, you must pay additional royalties due, plus late payment
interest calculated under Sec. 1218.202 of this chapter from the date
you took the deduction to the date you repay the difference.
(b) If the actual washing allowance is greater than the amount you
claimed on Form ONRR-4430 for any month during the period reported on
the allowance form, you are entitled to a credit without interest.
[FR Doc. 2014-30033 Filed 12-19-14; 4:15 pm]
BILLING CODE 4310-T2-P